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Pore-Pressure and Wellbore Stability analysis to mitigate High cost of unscheduled drilling events

May 20, 2021 / GEDLblogger / 0 Comments

A lack of accurate pore-pressure prediction and wellbore stability analysis can result in unscheduled drilling events, such as blowouts, kicks, hole washouts, wellbore break- out, and stuck pipe. Undetected abnormal pore pressure and wellbore instability also adds to drilling nonproductive time and increase drilling costs in millions of dollars and sometimes leads to abandoning the well before reaching its objective.

Integration of predrill pore-pressure and geomechanics analyses with real-time monitoring consistently provides an effective way to prevent drilling failure and improve well-construction efficiency.

Abnormal pore pressures can cause serious drilling incidents, such as unwanted fluid influx to wellbore (Kick) and well blowouts, if the pressures are not predicted accurately. This can lead to erroneous mud-weight design plan that can contribute to wellbore instability.

A lack of an accurate wellbore-stability prediction can also cause borehole breakouts and in hole closure, pack off, and collapse in cases of tensile and compressive shear failures leading to mud loss and lost circulation through hydraulic fractures and in severe cases can lead to a total lost borehole. Estimated cost to the drilling industry for hole stability problems range from 600 million to 1 billion dollars annually.

Relative cost of unscheduled events caused by wellbore stability problems

When the mud weight, or equivalent circulating density (ECD), is less than the pore pressure, the wellbore experiences splintering failure in shale formation. In this case, wellbore washouts or fluid kicks resulting from underbalanced drilling may occur.

A well may not have fluid kicks in an underbalanced-drilling scenario if impermeable formations that is not over-pressured are penetrated. When the mud weight or ECD is less than the shear-failure gradient or borehole collapse pressure gradient, the wellbore experiences shear failure (or wellbore elliptical enlargement, breakout, or collapse). Wellbore fracturing occurs when mud pressure exceeds the capacity of near-wellbore rock to bear tensile stress and the drilling fluid creates hydraulic fractures.

The drilling-induced fractures may cause drilling-fluid losses and even a total loss of drilling fluid returns (lost circulation). Maintaining wellbore stability and preventing these costly problems require an accurate prediction of the conditions that cause wellbore failures, including pore pressure and safe-mud-weight operating window.

PP=Pore pressure, SFG=Shear failure gradient, FG=Fracture gradient

Pore-pressure prediction

Pore pressure is the fluid pressure in the pore space of the formation. Pore-pressure analyses include three aspects:

Pore pressure analysis before drilling a well include: Seismic data analysis and interpretation in the plan well location; Well-logging, and drilling data in offset wells if available
Pore pressure analysis while drilling a well (qualitative and quantitative): Drilling parameters and mud-logging data; Logging-while-drilling (LWD) or measurement while-drilling (MWD) data
Pore pressure analysis after drilling the well: Wireline log analysis (Sonic log, Resistivity log etc.)

Pore pressure prediction from seismic data analysis before drilling

Bowers (1995) proposed that the seismic interval velocity and effective stress have a power relationship. On the basis of this relationship, pore pressure can be obtained from seismic interval-velocity data (Reflection times to transit times) in the planned-well location. The seismic data transform in terms of depths interval velocities and interval travel times are used for pressure gradient calculation for determination of (Overburden pressure and gradient, Pore pressure and gradient, Fracture pressure and gradient).

Pore pressure gradient from seismic section

Pore pressure prediction from wireline logs and logging while drillings logs

The analysis of wireline logs before drilling for offset wells and logging while drilling (LWD) allows the calculation of:

Overburden pressure and gradient
Pore pressure and gradient
Fracture pressure and gradient

The wireline logs generally used for pressure prediction and evaluation are: Sonic Logs, Induction Logs (Resistivity Logs) and Density Logs.

Pressure prediction and evaluation from drilling and mud-logging data

The acquisition and interpretation of drilling and mudlogging data represent a very important group of techniques which have the advantage to be available more or less in real time while drilling. These methods can be:

Qualitative: Which, if analyzed in their completeness, can provide significant information about the actual status of the well and alert the drilling team of dangerous and abnormal conditions while drilling. Among the qualitative techniques base on drilling and mudlogging data include:

Drilling Rate
‘d’ exponent, Sigma log
LWD (Resistivity, Density, Sonic)
Drag and torque
Mud pit level, Return flow, Pump Pressure (kick)
After Lag Time: Gas, (BG, CG, Pump off Gas) MW (out), Cuttings Shape/Size, Lithology (anhydrite, known marker, etc.), Shale density, Shale factor, Temp(out)

These are discussed in : “Pore-Pressure and Wellbore-Stability Prediction for Prevention of Drilling incident”.

2. Quantitative: Which ensure the quantification of the pressures acting in and around the well and the related risk levels. These include:

Overburden gradient calculation
Formation Pressure calculation by:
Equivalent Depth Method
Ratios Method
Eaton Method
Fracture Gradient Calculation by:
Eaton Method
Daines Method

These are discussed in “Quantitative Methods of Real-Time Pore Pressure and Wellbore Stability Detection”.

After the wellbore – Near Wellbore Stress-State

Before drilling, rock stress is described by the in-situ stresses; effective overburden stress, effective minimum horizontal stress, and the effective maximum horizontal stress. These stresses are designated by (σ₁, σ₂, σ₃).

As the hole is drilled, the support provided by the rock is removed and replaced by hydrostatic pressure. This change alters the in-situ stresses. The stress at any point on or near the wellbore can now be described in terms of: Radial stress acting along the radius of the wellbore; Hoop stress acting around the circumference of the wellbore (tangential); Axial stress acting parallel to the well path. These stresses are designated by (σ_r, σ_ø, σ_z)

Near wellbore stress state and Shear stress

Hoop Stress σ_ø

Hoop stress is dependent upon wellbore pressure, in situ stress magnitude, orientation, pore pressure, hole inclination and direction. Wellbore pressure is directly related to mud weight/ECD.

For a vertical wellbore with equal horizontal stresses, hoop stress is dependent upon the mud weight and the magnitude of the horizontal stresses and is equally distributed around the wellbore

A deviated well creates unequal distribution of hoop stress around the wellbore due to the redistribution of the horizontal and vertical stresses. Hoop stress acting on a cross-section of the wellbore is maximum at the sides of the wellbore perpendicular to the maximum stress. The same is true when drilling a vertical well in an in-situ environment of unequal horizontal stress. Hoop stress is maximum at the side of the wellbore perpendicular to the maximum horizontal stress.

Axial Stress σz

Axial stress is oriented along the wellbore path and can be unequally distributed around the wellbore. Axial stress is dependent upon; in situ stress magnitude and orientation, pore pressure, and hole inclination and direction. Axial stress is not directly affected by mud weight.

For a vertical well with equal horizontal stress, axial and vertical stress are the same. Axial stress in a deviated well is the resolution of the overburden and horizontal stresses.

Radial Stress σr

Radial stress is the difference in wellbore pressure and pore pressure and acts along the radius of the wellbore. Since wellbore and pore pressures both stem from fluid pressure acting equally in all directions, this pressure difference is acting perpendicular to the wellbore wall, along the hole radius.

Hoop (σø), radial(σr), and axial (σz) stress describe the near wellbore stress-state of the rock. Mechanical stability is the management of these stresses in an effort to prevent shear or tensile rock failure. Normally the stresses are compressive and create shear stress within the rock. The more equal these stresses, the more stable the rock.

Whenever hoop or radial stress become tensile (negative), the rock is prone to fail in tension. Many unscheduled rig events are due to loss of circulation caused by tensile failure.

Tensile failure due to negative hoop stress

Mechanical stability is achieved by controlling the parameters that affect hoop, axial, and radial stress.

Wellbore stability controllable parameters:

Mud weight (MW)/Equivalent circulating density (ECD),
Mud filter cake,
Well path – Inclination and azimuth,
Drilling / tripping practice.
Time dependent effect

Mechanical stability of the well is also impacted by drilling fluid/formation interaction. Chemical instability eventually results in mechanical failure of the rock in shear or tension.

Effect of Mud Weight/ECD

Mud weight, ECD, and pressure surges on the wellbore directly affect hoop and radial stress. An increase in MW decreases hoop stress and increases radial stress. Similarly, a decrease in MW increases hoop stress and decreases radial stress. The result on wellbore stability is dependent upon the magnitude of the mud weight increase/decrease.

Mud Filter Cake and Permeable Formations

The filter cake plays an important role in stabilizing permeable formations. An ideal filter cake isolates the wellbore fluids from the pore fluids next to the wellbore. This is important for hole stability and helps prevent differential sticking as well.

If there is no filter cake, the pore pressure near the wellbore increases to the hydrostatic pressure; the effective radial stress is zero. The simultaneous decrease in effective hoop stress causes the stress-state to move left in the stability envelope; decreasing the stability of the formation. An ideal filter cake helps provide for a stable wellbore. The chemical composition of the mud and permeability of the formation control the filter cake quality and the time it takes to form.

Hole Inclination and Direction

The inclination and direction of the wellbore greatly impacts the stability of the well. Unequal distribution of hoop and axial stress around the circumference of the well tends to make the wellbore less stable.

For Equal Horizontal Stress: Drilling a horizontal well causes the hoop and axial stress distribution around the wellbore to change. Before drilling from vertical, the hoop stress is equally distributed. As angle increases to horizontal, the hoop stress on the high and low side of the wellbore decreases, but the hoop increases greatly on the perpendicular sides.

Bottom-hole Temperature

Temperature changes associated with mud circulation during drilling may alter the rock properties. The change in rock properties may reduce or enhance borehole failure depending on the thermal effect. Temperature fluctuations may also influence the stress distribution around the borehole. As the temperature increases, the tangential and vertical stresses will increase. However, temperature fluctuations will not influence the stress anisotropy around the borehole as the thermal effect should alter the tangential and vertical stresses by an equal amount.

Time-dependent effects.

Reactive shale instability is also time-dependent, and is governed by two intrinsic mechanisms: (a) consolidation and (b) creep. Consolidation is due to pore pressure gradients induced by fluid communication between the mud and pore fluid. Creep is described by a change of strain at a constant effective stress level. Both of these mechanisms will result in hole size reduction. In practice, it is difficult to distinguish between creep and consolidation effects. In general, consolidation will occur shortly after loading, while creep will govern later deformation. The mud pressure and properties, and the temperature in the rock may vary during drilling operations, which in turn enhance borehole instability. All these parameters make it more difficult to directly pursue the time-dependent effects. The best approach is to quickly isolate the rock with a casing to minimize the potential borehole instability.

Providing a stable wellbore

Potential Stability Indicators

If the answer to any of the questions below is “yes”, preventive measures should be taken:

Indications of tectonic activity in the area?
Sudden pressure transition zones expected?
Adverse formations expected (reactive shale, unconsolidated or fractured
formations, abnormal or sub normally pressured zones, plastic formations?
Is wellbore inclination greater than 30?

2. Identify Stress Regime

σ1= Greatest effective stress

σ2= Intermediate effective stress

σ3 = Least effective stress

3. Determine Magnitude of In Situ Condition (sv , sh , sH)

Overburden – sv (Obtained from density logs of offset wells).
Formation Pore Pressure -pp (Estimated by seismic and logs).
Minimum Horizontal Stress – sh (Determined by LOT and/or logs).

4. Use Core Tests or Logs to Determine Formation Rock Strength or Use Logs to determine: Effective Compressive Stress. Rock strength is estimated through correlations with sonic density logs since slow sonic velocity and high porosity generally relate to lower rock strength.

5. Select Mud System and Determine Mud Weight Window: Stability spreadsheets and analysis tools are used to determine the mud weight window for each hole section.

6. Avoiding Stability Problems

Select an inhibitive mud for reactive formations.
Casing points should allow for mud weight windows determined from stability analysis
Maintain mud weight/ECD in stability window. Use down hole. ECD monitoring tools in critical wells.
Optimize well trajectory based on drilling days vs. stability.
Plan for effective hole cleaning and stuck pipe prevention.
Follow safe drilling practices. Control ROP, surge pressures.

Mechanical Stability

Mechanical instability has stated earlier is related to incorrect mud weight /ECD and/or well trajectory. Too low mud weight can cause hole cavings or collapse resulting in stuck pipe. Too high mud weight /ECD can cause excessive fluid losses to the formation or total loss of returns

Warning Signs of Mechanical Stability Problems

Large size and volume of cavings over shakers.
Erratic increase in torque/drag.
Hole fill on connections or trips
Stuck pipe by hole pack-off /bridging.
Restricted circulation /increases in pump pressure.
Loss of circulation.
Loss/gain due to ballooning shales.

Preventing Mechanical Stability Problems

The constraints on wellbore pressure are dictated by formation pressure on the low end and fracture strength on the high end. Hydraulics planning must also consider minimizing the shock load imposed to the wellbore.

Measures to prevent/correct mechanical stability problems include:

Increase the mud weight (if possible). The mud weight values should be determined using a stability analysis model and past experience if drilling in a known field.
If drilling fractured formations, it is not recommended to increase MW. Increase the low-end rheology (< 3 RPM Fann reading).
Improve hole cleaning measures. Maintain 3-rpm Fann reading greater than 10. GPM for high-angle wells equal to 60 times the hole diameter in inches and half this value for hole angle of less than 350.
Circulate on each connection. Use back reaming and wiper trips only if hole conditions dictate.
Minimize surge/swab pressures.
Monitor torque/drag and the size and amount of cuttings on shakers.

Wellbore stability analysis

Borehole collapse could be predicted by adopting compressive failure analysis in conjunction with a constitutive model for the stresses around the borehole.

The most commonly used failure criterion in wellbore stability analysis is Mohr-Coulomb criterion This criterion involves only the maximum and minimum principal stresses, σ1 and σ3, and therefore assumes that the intermediate stress σ2 has no influence on rock strength. This failure criterion has been verified experimentally to be good in modelling rock failure, based on conventional triaxial tests (σ1 > σ2 = σ3). On the other hand, in practice, the Mohr-Coulomb criterion has been reported to be very conservative in predicting wellbore instability.

When drilling near massive structures such as salt domes or in tectonic areas, the horizontal stresses will differ and are described as polyaxial stress state (σ1 >σ2 > σ3). A new true-triaxial failure criterion called the Mogi-Coulomb criterion has been developed to calculate the resultant shear stress in polyaxial state. This failure criterion is a linear failure envelope in the Mogi domain (τoct-σm,2 space) which can be directly related to the Coulomb strength parameters, cohesion and friction angle. This linear failure criterion has been justified by experimental evidence from triaxial tests as well as polyaxial tests. It is a natural extension of the classical Coulomb criterion into three dimensions.

As the Mohr-Coulomb criterion only represents rock failure under triaxial stress states, it is expected to be too conservative in predicting wellbore instability. To overcome this problem, Geodata Evaluation & Drilling Engineers utilized a new 3D analytical model to estimate the mud pressure required to avoid shear failure at the wall of vertical, horizontal and deviated boreholes. This has been achieved by using linear elasticity theory to calculate the stresses, and the fully-polyaxial Mogi-Coulomb criterion to predict failure.

Conclusion

Determining the safe-mud-weight range is critical to improve well planning, prevent wellbore-stability problems, and reduce borehole drilling-trouble time in the oil and gas industry. Accurate pre-drill pore-pressure prediction and well-bore-stability analysis are key to improving drilling efficiency and reducing risks and costs.

Seismic data, regional geology data, formation-pressure measurement, and well-log data from offset wells can be used for predrill pore-pressure prediction.

Pore-pressure profile, in-situ stress, rock strength, image log, caliper log, and drilling events in offset wells can be used to obtain a valid wellbore stability solution for predrill wells. Real-time analysis can be performed while drilling, either on site or remotely, to update the predrill model, reduce uncertainty, avoid drilling incidents, and increase drilling efficiency.

Talk to us for your upcoming wellbore stability analysis solution

We have specialized software and highly experienced Drilling engineers to provide training to your drilling department workforce in wellbore stability analysis solution. Contact us at www.geodatadrilling.com Phone: +234 8037055441

Wellsite Geologist in the Oil and Gas industry – Advantage of hiring one

February 11, 2021 / GEDLblogger / 0 Comments

Consultant wellsite geologists, in the oil and gas industry, provide contract services to clients by bringing skill and experience in different perspective of drilling and geology which allows the geology consultant to help companies identify and solve several different problems.

The Wellsite Geologist effectively supervise geological operations at the wellsite during drilling and acts on behalf of the operating oil company, reporting to the Operations Geologist. The role is also analytical in nature, with geological interpretations used to check that the well is meeting geological targets and also to advise drilling personnel on the geological causes of problems experienced during drilling as drilling equipment and fluids interact with the rocks forming the borehole wall. Early recognition of unpredictable geological anomalies can lead to rapid and cost-effective solutions being applied, making the well safer as well as within budget.

Wellsite geologist

The wellsite geologist (WSG) and the company man (DSV), or drilling supervisor are usually the only oil producing company representatives at the rig. Both are oil company supervisors, but the geologist oversees a few teams while the company man supervises the entire drilling operation.

A Wellsite geologist is an oil company subsurface representative at well site or drilling location. They are involve in geological supervision at the well site

The basic function of wellsite geologist is to analyze drill cuttings obtain by mudloggers while drilling by identification and description of lithology with respect to depth which is an aspect of formation evaluation.

Wellsite geologist is often consultant who offer advice to the oil company and take some decisions in conjunction with the operation geologist at office in town. An example of this is when there is a need to stop drilling for casing or coring operation.

The geologist works under the supervision of operations geologists. They are located in the town offices and are the ones to whom wellsite geologist transmit all their report. Wellsite geologists are the main contact point between the oil rig and the geology and geophysics team in town. We communicate and discuss their intentions, plans and concerns to the teams at the wellsite.

What are the functions of wellsite geologist?

Wellsite geologist are responsible for well site geological supervision and all geological related activities at drilling site. The following are responsibilities of wellsite geologist:

Drill cuttings analysis and description

One of the basic duties is the identification and description of drill cuttings circulating out of the borehole with respect to depth. The description is often standardized and defined by each oil company. The wellsite geologist can classify the rock cuttings, check for evidence of borehole instability and confirm the presence of hydrocarbons. Drilling cuttings are analyzed and described using a stereoscopic microscope under white reflected light. To help identify the presence of hydrocarbons, a UV Box (Ultraviolet Box) is also used. Hydrocarbons will have a variable, but identifiable, brightness when exposed to ultraviolet light.

Several other tests are performed to carry out the formation evaluation. Such tests involve chemicals such as hydrochloric acid, to detect calcium carbonate content, and phenolphthalein, to detect the presence of cement and differentiate it from the formation.

Data correlations and decisions

The wellsite geologist analyses and interpret MWD/LWD data for confirmation of lithology, fluid type (oil, gas. water) and compare data gathered during drilling to prediction from seismic section and offset wells for determination of actual formation tops and reservoir sands to ensure the well is drilling in the formations forecasted for a given depth – deeper or shallower relative to the forecast?

When offset well data MWD/LWD and wireline logs are available to the wellsite geologist, data correlation can be carried out which can help to foresee important events like significant gas changes, drilling breaks and potential hazards which occurred in offset wells. You may find the older offset logs usually printed in paper or in a pdf format. The raw data is usually in a LAS file format, which is the most common for the mudloggers and LWD/MWD services to distribute.

Wellsite geologist need to advise the base office and drilling team on the best course of action in several scenarios. As the field geologist you have the responsibility of advising the team to either carry on or stop drilling. Nowadays this is usually a decision made together with operation geologist at office base in town. One such example is selecting at which depth drilling operations must stop in order to set casing or take a core sample.

Formation evaluation services team supervision

There are a few teams and services which wellsite geologists supervise. These are the mudlogging, MWD and LWD, wireline logging, core handling, micro and nano paleontologists. The geologist performs quality control and assurance of these services and the data they provide. These requirements can change from Oil Company to oil company.

Coring operations

The geologist is the key figure at the wellsite for taking decision with the office in town on when to stop normal drilling operations, as we approach coring point. Again, wellsite geologist need to use several correlations logs, drill cuttings , offset mudlogging, LWD data and other formation evaluation methods. When reaching coring point the drilling team starts to pull out of hole to proceed with the coring operation.

During coring operation, Wellsite geologist evaluates the few cuttings coming out of the wellbore while cutting the core. When the core is at surface, geologist take core chips from each meter (3 feet) of the entire core to evaluate the presence of hydrocarbons and to decide if coring operations should continue or stop in order to resume regular drilling operations (usually reaching the Total Depth). We must handle, or supervise the handling, of the core on surface ensuring proper markings and saw cutting as per oil company standards.

Casing point determination

The role of the geologist, for this operation, will be similar to the coring point approach as our main focus is analyzes of drill cuttings and correlating data with offset wells and ensure that there are no permeable / porous formations close to the bottom of the hole when we reach casing point, or in the rathole immediately below the casing shoe, as that increases substantially the risk of having losses during the cement job that will be performed after running the casing itself.

Geosteering and Horizontal drilling

Wellsite geologist (depending on the oil producing company) coordinate wellsite Geosteering operation in conjunction with Base Operation Geologist by analyzing and interpretation of real time data (Well inclination, Azimuth, correlation, Lithology, Biostratigraphy, reservoir porosity, formation dip and compare with the pre-drill geological model derived from seismic and offset Well data for decision-making as whether to increase inclination or to place the borehole trajectory higher in terms of TVD or to aim for a series of forward target points coordinates and to maintain direction/angle of inclination required at the bit when target is reached) while drilling horizontal Well.

Reporting

Wellsite geologist have several reports to prepare daily, weekly, and at the end of the well. Some of the daily reports are the Daily Geological Report and the Lithology Log. These reports are updated with geological data, ongoing operations and important events.

There is also an End of Well Report or Final Well Report. This is produced and completed during the course of operations at the wellsite. They are delivered as updates to the operations and petroleum geologists during drilling operations. When drilling operations end these reports continue to be completed in the offices in town. They are updated until the end of all wellsite operations and only end when all the data from the entire well is obtained. Final completion of these reports will be carried out by the onshore geology team or the oilfield geologist, if asked to. There are several software packages available for us and these are usually provided by the oil company. Training on how to use them is one of the geological consultant’s responsibilities. For example, some of these software packages will allow you to produce the lithology logs, composite logs and other types of logs which may be required.

Safety and communication

HSE (Health, Safety and Environment) is a key aspect at the wellsite. The geologist is a leader and sets the example at all times encouraging others to work in safe conditions. Safety is one of the most important aspects of the entire operation.

Communication is also key to the success of the operations. Geologist communicate frequently with both the onshore office and the teams at the wellsite. This can reduce misunderstandings and mistakes. Make your teams feel comfortable enough to ask you anything in case of any doubts.

Talk to us for your upcoming wellsite geology consultancy requirement

We specialize in providing highly experience wellsite geologist to clients of all sizes in the oil and gas industry. Contact us at www.geodatadrilling.com Phone: +234 8037055441

Quantitative Methods of Real-Time Pore Pressure and Wellbore Stability Detection

January 6, 2021 / GEDLblogger / 1 Comment

Our pore pressure computer program (Geopressure software) for detection / analysis of abnormal pore pressures during mud logging (drilling) operation currently supports the following methods:

Overburden gradient calculation

Formation Pressure calculation by:

Equivalent Depth Method
Ratios Method
Eaton Method

Fracture Gradient Calculation by:

Eaton Method
Daines Method

Shear failure gradient (SFG) or borehole collapse pressure gradient calculation by:

Mohr-Coulomb failure criterion

Normal compaction trend line (NCTL) Methods

These are the most common methods in current use, and require a shale sensitive log, a porosity-sensitive log, and an overburden gradient curve corrected for water depth.

Compute overburden gradient and correct for water depth
Identify the shale points. Select porosity points at the shale points.
Determine the normally compacted interval in the porosity-sensitive log and fit it with a normal compaction trend line (NCTL)

Compare each point of the porosity log to the NCTL and compute abnormal formation pressure using an appropriate method.

In practice, fracture gradient also is calculated and plotted with the pressure/overburden curves.

Estimating Overburden Gradient

For evaluation of formation pressure
For calculation of fracture gradient

API

metric

The Operator can hand-calculate an approximate overburden curve from formation bulk densities for several representative depths over the interval to be drilled. Representative bulk densities may derive from wireline log data, from ‘shale’ (cuttings) densities, or seismic (interval velocity) data.

If we have an electric log for the formation density, we can use it to calculate the overburden:

Divide the log into intervals of depth with similar density.

If the proposed well is offshore, the first two density intervals will be:

Air gap between elevation of flowline and mean sea level, with ρb= density of air

Water depth between mean sea level and sea bottom (mud line), with ρb = density of sea water.

Then fill the following form to calculate the overburden at the end of each depth interval:

Interval bottom (m)	Thickness (m)	Bulk density (kg/)	Overburden pressure in the interval (kg/cm2)	Total overburden pressure (kg/cm2)	Overburden gradient (kg/cm2/10m)
150	150	1.06	S=150*1.06/10 = 15.9	15.9	GS= 15.9*10/150 = 1.06
400	250	1.70	S=250*1.70/10 = 42.5	15.9 + 42.5 = 58.4	GS= 58.4*10/400 = 1.46
700	300	1.80	54.0	112.4	1.61
1070	370	1.89	69.9	182.3	1.70

Overburden calculation by depth

Plotting the overburden gradient versus depth gives a curve

The equation of the curve is:

S= a(Ln(Depth))2+ bLn(depth) + c

The coefficients a, b and c are regional characteristics

If no density log is available,

a ”hard formation” or a “soft formation” set of coefficients a-b-c is used.

The default coefficients, known as ‘soft’ and ‘hard’ values, were constructed from data for a number of wells in two separate areas:

‘Soft’ coefficients (relatively pure shales)

a = 0.01304

b = -0.17314

c = 1.4335

‘Hard’ coefficients (siliceous shales)

a = 0.01447

b = -0.1835

c = 1.4856

Clients most often prefer to use sonic log densities, or seismic transit times, to calculate formation bulk densities. This set of calculations is known as the AGIP method (Belotti, et al., 1978).

The transit times of sound waves passing through a given formation can be used to define the porosity of the rock, as in the equation below:

Where:

⧍t_log = Transit time reading from the sonic log (μsec/ft)

⧍t_m = Rock matrix transit time (μsec/ft)

⧍t_f = Transit time of the formation fluid (μsec/ft)

∅ = Porosity (decimal value from 0 to 1)

In practice, the approximate value of ⧍t_fis 200 μsec/ft. The values for ⧍t_m can be approximated as below

Lithology	Density (kg/l)	⧍tma (μsec/ft)
Dolomite	2.87	43.5
Limestone	2.71	43.5 to 47.6
Sandstone	2.65	47.6 to 55.6
Anhydrite	2.96	50
Salt	2.02	67
Shale	3*	47*

Values of rock matrix and density

Three formulae describe the relationship between porosity and transit times for different types of sedimentary formations.

Unconsolidated Sand

After approximating the porosity, the bulk density is a function of:

Where:

ρb = Bulk density for the interval, g/cc

ρm = Rock matrix density, g/cc

ρf = Formation fluid density (usually 1.03), g/cc

Requirements for formation pressure/fracture gradient FP/Frac Calculations

For estimated formation pressure calculations, you will need:

DCN (‘normal’ trend of compaction increase)
Overburden gradient
Normal formation pressure (mud density equivalent) or equilibrium density at a specific depth.

For fracture gradient calculations, you will need:

Effective vertical stress
Tectonic stress (if Daines Method is used)
Formation pressure gradient.

Estimating formation pressure Pf

Our Pore Pressure Engineers can calculate formation fluid pressures from any of the following data:

Seismic interval velocities
Normalized drilling parameters (‘d’ Exponent)
Shale density
Wireline or MWD logs, including resistivity/conductivity, sonic and direct measurement of downhole pressure
RFT/DST (providing direct measurement of pressures)
Kick.

In practice, ‘d’ Exponent usually provides the primary pressure data, with the other processes used to verify or correlate the results.

Equivalent Depth Method

We can apply the Terzaghi equation for Overburden pressure, (S= σ+ Pf) . We know that we have the same compaction in A and B, so the stress S must be the same in both points! σA = σB

We can write:

σB = SB – PfB and σA = SA – PfA

As σA = σB we have:

SB –PfB = SA –PfA

Thus:

PfA = PfB + (SA -SB)

Overpressure applies the equivalent depth method via the following equation:

DeqA=Sa – Hb/Ha * (Sb – DeqB)

Where:

DeqA = Equilibrium density at depth A

Sa= Overburden gradient at depth A

Ha= Depth A

DeqB= Equilibrium density at depth B

Sb= Overburden gradient at depth B

Hb= Depth B

Ratios Method

Application:’d’ Exponent, shale density, wireline/MWD logs(resistivty and sonic log)

Principle:

The difference between observed and ‘normal’ values of a parameter is proportional to the increase in pressure.

As an example, for ‘d’ Exponent, the calculation is:

where:

PF = Formation pressure gradient (mud density equivalent)

H= ‘Normal’ pressure gradient (mud density equivalent)

Eaton Method

Application: Interval velocities, ‘d’ Exponent, wireline/MWD logs(resistivty and sonic log)

The Eaton Method uses the principle that changes in the overburden gradient govern the ratio between the observed and ‘normal’ values of a given parameter.

Shale Resistivity:

Pf Gradient=OVBG – (OVBG – H)*(Rsh_{O /} Rsh_N)^1.2

With H: normal hydrostatic gradient

Rsh_N: Theorical shale resistivity on normal trend (B)

Rsh_O: Observed value of shale resistivity (A)

OVBG: Overburden gradient observed at observed depth

Sonic:

Pf Gradient=OVBG– (OVBG – H)*( Dt_N/Dt_O)^3.0

With H: normal hydrostatic gradient

Dt_N: Theorical transit time on normal trend (B)

Dt_O: Observed value of transit time (A)

OVBG: Overburden gradient observed at observed depth

Formation tests

DST or RFT tests give a direct evaluation of the Pf

Estimating Formation Pressure from Kick

In most kicks, the invading fluid does not enter the drill pipe. Thus, the Shut-in Drill Pipe Pressure (SIDPP) represents the amount by which formation pressure exceeds the hydrostatic pressure of the mud column.

Formation pressure equals the sum of mud hydrostatic pressure (inside the drill pipe) plus Shut-in Drill Pipe Pressure (SIDPP).

metric

API

Calculating Fracture Gradient

Liquid exerts pressure which is equal in all directions.

When solids are subjected to external force, it reacts by distributing internal load called stress -giving to stress ellipsoid.

If loading is perpendicular to eliminatory surface the stress is normal.

If loading is tangential to the eliminatory surface shear stress results.

σ = OVB – PF

Fracture occurs when the stress exceeds tensile strength of the rock.

The pressure in this case is fracture initiating pressure. – FP1

If the pressure is suddenly reduced the fracture closes.

To reopen the existing fracture less pressure required – FP2

A surge may open a fracture, afterwards the mud that was holding the hole may not hold any more. Stress is a pressure force per unit area and acts normal to the selected plane.

Stresses acting at any point can be resolved in to 3 mutually perpendicular stresses.

Maximum – σ1

Intermediate – σ2

Minimum – σ3

Relaxed area : Low topography σ1 is vertical and equal to the weight of the overlying rocks.

σ2 and σ3 are horizontal and normal to σ1 . σ1 > σ2 = σ3

Extreme case:

Tectonically stressed area : Thrust faults etc. σ3 is vertical and equal to weight of overlying rocks.

σ1 and σ2 are horizontal.

When fracture occurs S3 is overcome.

Fracture Pressure F = S3= σ3 + PF σ3 = K X σ1

F – PF = K X σ1

K X (OVB – PF)

( F – PF) / (OVB -PF) = K (Stress Ratio).

Thus K can be calculated after LOT. Values of K differ with depth.

Hence a plot of Depth X K is necessary to get proper value of fracture pressure.

Poisson’s Ratio

Eaton introduced Poisson’s ratio to account for variable overburden gradient.

The ratio of lateral unit strain to the longitudinal strain in a body that has been stressed longitudinally within its elastic limits.

Measure an ability of the rock to deform within its limits.

Fracture Pressure F = [ μ/ ( 1- μ)] σ1+ PF

Consider flat lying stratum of semi-infinite extent and weight of overlying strata is the only source of stress.

σ H = [ μ / ( 1- μ)] σ1 μ = 0.25

= [ 0.25 / ( 1 – 0.25) ] σ1

= 1 / 3 (σ1 )

Calculating Frac: Eaton Method

As described previously, Eaton uses Leak-off Test results to compute Poisson’s ratio; this ratio is then use to determine the corresponding fracture gradient:

The fracture gradient at a specific depth is then calculated as a function of:

Calculating Frac: Daines Method

The Daines Method refines the Eaton calculation by allowing for a variable Poisson coefficient based on rock type drilled, and by introducing a correction factor for tectonic stress.

The basic Daines calculation is:

Frac = σ_{t +}σ (μ)/(1 – μ) + PF ; where σ is vertical effective stress

Data from the first Leak-Off test (in a compacted formation) allows back-calculation of the ratio of superimposed tectonic stress:

σ_t = Frac – σ ( (μ )/(1 – μ)+ PF )

To determine the tectonic stress at the Leak-off Test depth:

σt = Frac- σ’1 X μ/1 – μ+ P

Where:

σt = tectonic stress

Frac = Formation fracture gradient (mud weight equivalent); determined from leak-off test pressure

σ’1 = maximum effective compressive stress

μ = Poisson’s Ratio, as determined from table on next slide

P = estimated formation pressure gradient (mud weight equivalent).

Daines suggested the following Poisson’s ratios for different lithologies (use the one that most closely corresponds to the rock type at the Leak-off Test depth:

Rock type	μ	Rock Type	μ
Clay	0.17 to 0.50	Sandstone cont.
Conglomerate	0.20	poorly sorted, shaly	0.24
Dolomite	0.21	fossiliferous	0.01
Limestone:		Shale:
micritic	0.28	calcareous	0.14
sparitic	0.31	dolomitic	0.28
porous	0.20	siliceous	0.12
fossiliferous	0.09	silty	0.17
argillaceous 0.17	0.17	sandy	0.12
Sandstone:		kerogenaceous	0.25
coarse	0.05 to 0.10	Siltstone	0.08
medium	0.06	Slate	0.13
fine	0.03	Tuff, glassy	0.34

After Daines, Journal of Petroleum Technology, 1982

The maximum effective compressive stress is determined as follows:

σ’1 = S – P

Where:

S = overburden gradient

P = estimated formation pressure gradient (mud weight equivalent).

Indicators from Wellbore Instability

When the mud weight is inappropriate, wellbore instability events occur while drilling, which can help to diagnose the overpressure and to adjust mud weight in real-time drilling operations. Wellbore instability can be classified into two categories:

Shear failures
Tensile failures.

Shear failures

When the downhole mud weight is less than the shear failure gradient (SFG, or borehole collapse pressure gradient), the wellbore experiences shear failure. Shear failure is mainly caused by the condition in which the applied mud weight is lower than the SFG. The indicators of shear failures while drilling include hole enlargement (borehole breakout), hole closure, tight hole (overpull), high toque, hole fill after trip, hole bridging, hole pack-off, and hole collapse.

Some of these indicators may be caused by swelling shale when the water-based mud is used because of the chemical reaction between the mud and the shale formation. Therefore, it needs to identify the causes of the failures.

Here we use a vertical well as an example to illustrate the relationship of wellbore instability and pore pressure. Based on Mohr-Coulomb failure criterion, the minimum mud weight to avoid borehole shear failure can be obtained from the following equation:

P_m = 1 – sin φ/2 (3σ_{H –}σ _{h – UCS}) + p_p_sinφ

Where

P_m = minimum mud pressure or collapse (shear failure) pressure

_φ = angle of friction of the rock

UCS = rock uniaxial compressive strength

p_{p =}Pore pressure

σ_H, σ _h = the maximum and minimum horizontal stresses, respectively.

The horizontal stresses are most important parameters for analyzing wellbore stability, which can be obtained from either field measurements or calculations

The equation above shows that the shear failure is directly related to the pore pressure; a higher pore pressure needs a heavier mud weight to keep the wellbore from the shear failure. Therefore, wellbore instability can be used as an indicator of an overpressured formation.

Tensile failure

Tensile failure occurs when the mud pressure exceeds the capacity of the near-wellbore rock to bear tensile stress. If the downhole mud weight is higher than the fracture gradient, the formation will be fractured to create hydraulic fractures (or drilling-induced tensile fractures). Real-time indicators of drilling-induced tensile failures include hole ballooning, drilling mud losses, and lost circulation. Reducing mud weight, adding lost circulation materials (LCM), or applying wellbore strengthening technique are possible cures for the drilling-induced tensile failures.

Procedures of Real-Time Pore Pressure Detection

For real-time pore pressure detection and monitoring, the following steps can be performed:

Construct predrill petrophysical and pore pressure model and calibrate the predrill model to offset wells if they are available. The model includes methods of resistivity, sonic, Dxc, and so on. The model should include uncertainties and address drilling challenges and potential issues.

Apply the model to the real-time well. It particularly needs to have a calibrated NCT for each method.

Connect the model to real-time data (e.g., use Connect WITSML to connect LWD and MWD tools), so that the real-time data can be automatically loaded to the model. The model can then automatically calculate pore pressures based on the NCT using the real-time LWD and MWD data.

Compare the real-time calculated pore pressure to downhole mud weight (ESD, ECD); to determine if the mud weight is sufficient, particularly it needs to identify whether or not the mud weight is less than the pore pressure gradient. Only comparing the real-time calculated pore pressure gradient to the mud weight is not enough to conclude an underbalanced drilling status. Therefore, it also needs to combine to other real-time indicators of pore pressures.

Adjust the models (mainly NCTs) based on the following data if they are available: real-time pore pressure measurement, well influx, mud pit gains, kicks, mud gas data, mud losses, drilling parameters, and borehole instability events (e.g., cavings, torque, fills, and pack-offs).

Alert and inform the rig for action when the pore pressure is lower (underbalanced) or close to the downhole mud weight.

Liaise with technical expert group on all issues related to unplanned drilling operations, ECD, and pore pressures.

Make postwell knowledge capture and transfer within the appropriate organizations and systems.

The real-time monitoring should ensure that:

Pore pressure is continuously monitored and indicators of the abnormal pressures are identified;

Real-time pore pressure methods, estimates, and updates are discussed routinely with all involved monitoring parties to provide a consistent interpretation to the rig operations;

Abnormal pore pressure events are identified as soon as possible;

The abnormal events, including significant observations, changes, or updates in pore pressure estimates, if they are occurring or imminent, need to be communicated to the operations (e.g., operation geologist and drilling engineer) quickly;

The appropriate actions of operations (e.g. raising mud weight when the pore pressure gradient is lower than the downhole mud weight) are taken quickly.

Talk to us for your upcoming Pore-Pressure and Wellbore-Stability Prediction requirement

Geodata Evaluation & Drilling LTD. Pore pressure consultant use specialist software to provide pore pressure profiles for your wells which are calibrated to offset well behavior for determination of optimum mud weight window for successful drilling operation. Contact us at www.geodatadrilling.com Phone: +234 8037055441

Pore-Pressure and Wellbore-Stability Prediction for Prevention of Drilling incident

January 6, 2021 / GEDLblogger / 0 Comments

Qualitative Pressure detection

When abnormal pore pressures are not accurately predicted in pre-drill stage or detected in real-time drilling, it may cause serious drilling incidents such as fluid influx to the wellbore, kicks, and even blowouts. Pore pressure analysis mainly includes three aspects, these includes:

1. Pre-drill pore pressure prediction.

Regional Geology,
Geophysical –Seismic

2. While drilling (Real time) pore pressure detection

Drilling Rate
‘d’ exponent, Sigma log
LWD (Resistivity, Density, Sonic)
Drag and torque
Mud pit level, Return flow, Pump Pressure (kick)
After Lag Time: Gas, (BG, CG, Pump off Gas) MW (out), Cuttings Shape/Size, Lithology (anhydrite, known marker, etc.), Shale density, Shale factor, Temp (out)

3. Post Well pressure Analysis

Wire Line Logs: Resistivity, Density, Sonic
Direct Pressure: DST, RFT/MDT

This article will focus on methods of while drilling (real-time) pore pressure detection based on overpressure linked to shale compaction anomaly

Drilling Rate – Rate of Penetration (ROP)

In shale, ROP decreases with depth because of decrease in porosity due to compaction. ROP tends to increase as the bit enters an under-compacted section. ROP depends on: Lithology, Compaction, Differential pressure, WOB (weight on bit), RPM (Rotation per minute), Torque, Hydraulics, Bit Type and Wear.

Factors Affecting ROP

Lithology – Drillability depends on: Porosity, Hardness (Calcareous clays), Plasticity, Abbrasiveness (Accessory minerals, such as siderite), Cohesion

Compaction – Compaction increases with depth. The under-compacted section is indicative of higher porosity. This results in increased drillability.

Differential Pressure – Difference of pressure between mud column and formation pressure. Increase in pressure of mud column decreases penetration rate.

Bit tooth impacts on formation, creating fractures. Further impact deepens the fractures, forming rock fragments.

Overbalance: Rock fragments are difficult to dislodge because of positive differential pressure. Mud Pressure > Formation Pressure

Underbalance: Rock fragments are forced away from formation face. Formation pressure > mud column

Effects of Overbalance:

Slower rate of penetration
Formation damage
Absence or low recovery of hydrocarbons C2-C5 (gas interpretation more difficult)
Problems for E-log interpretation.

Weight on bit – Changes in WOB affect drill rate; size of bit affects weight applied per unit of surface area

Weight on bit – in an inclined hole, apparent WOB recorded at surface is not representative of down hole WOB. The string may rest on the hole wall, reducing down hole WOB.

Weight on Bit – Generally ROP increases with WOB, up to a ‘flounder point’ which can vary with formation consolidation. (Threshold Weight : minimum weight required to start drilling. Unconsolidated rocks come apart just by jet action, Flounder Point : Drilling rate stops rising. Bit teeth become jammed with cuttings. Bit cleaning is less effective).

RPM – Relationship of RPM and drilling rate for a given formation. Increased RPM increase drilling rate.

Torque – Measurement of torque at surface is effect of bit and string (stabilizers etc.) MWD torque measured at the bottom is probably true indication of bit torque. (Increase in torque is balanced by twisting of the string. This shortens the string. Weight on bit decreases. The torque is released. String lengthens, WOB increases. The process keeps on repeating.

Hydraulics – Effect of hydraulics depends on consolidation of sediments under drilling. Increase in flow rate tends to increase ROP (faster clearing of cuttings from under bit).

Mud properties:

Viscosity: Low viscosity with turbulent flow = more effective cleaning of the bit face.

Water loss: Increased water loss may increase penetration rate by reducing time for mud pressure and pore pressure to reach equilibrium.

Suspended solids: Tend to reduce water loss; may dampen bit impact in some cases.

Bit Type and Wear – most often a consideration when tri-cone rock bits are in use.

Change of bit type will result in ROP trend change
Tooth wear may result in gradual ROP decrease that masks transition zone
Controlled drilling practices may mask transition zone
Diamond/PDC bits tend NOT to show ROP changes due to wear.

Various methods have been devised to “normalize” the rate of penetration. These attempt to eliminate the effects of drilling parameter variations and thus measure formation drillability. The simplest and most reliable solution is known as ‘d’ Exponent.

‘d’ Exponent

‘d’ Exponent is based on an empirical relationship between drilling rate, weight on bit, rotating speed and bit diameter, first suggested by Bingham (1964):

R/N = a (W/D)d

R = ROP, ft/min

N = RPM

W = WOB, pounds

D = Bit diameter, inches

‘a’ = lithological constant

‘d’ = compaction exponent

Jorden and Shirley (1966) solved for ‘d’ by introducing constants which would allow the use of standard industry units.

Bingham’s constant ‘a’ was assumed to be 1 (constant lithology) and thus is not included.

Original Jordan and Shirley Equation (API):

log ( ROP / 60 RPM )

d = ——————————-

log ( 12WOB / 106BS )

Where:

ROP = ft/hr

WOB = pounds

BS = Bit Size, inches

Original Jordan and Shirley Equation (metric):

1.26 -log ( ROP / RPM )

d = ——————————-

1.58 -log ( WOB / BS )

Where:

ROP = meters / hr

WOB = tonnes

BS = Bit Size, inches

‘d’ Exponent vs. Compaction Trend

Where lithology is constant, ‘d’ Exponent will represent:

the state of compaction (relative porosity)

differential pressure

A decrease in ‘d’ while drilling in an argillaceous formation is thus related to the degree of undercompaction and of the associated abnormal pressure.

Note: If measured depth and TVD differ significantly, ‘d’ Exponent should be calculated based on TVD.

Corrected ‘d’ Exponent (dcs)

‘d’ exponent values depend in part on mud density and pore pressure. Any change in differential pressure will thus affect ‘d’ Exponent.

Rehm and McClendon (1971) proposed a correction to account for this effect:

dcs = d ——-

ECD

NG = Normal Hydrostatic gradient – ppg (API) or kg/l (metric)

ECD = Equivalent Circulating Density – ppg (API) or kg/l (metric)

Dcs Bit Wear Correction

When rock bits are in use, the ROP tends to slow down because of tooth wear. The dcs can show a false increase, thus potentially masking a transition zone. Bit wear corrections have been developed to account for this effect.

Dcs Bit Wear Correction

The Galle and Woods Method

1.26 – log [ ( ROP * a ^P) / (RPM ) ]

d = ———————————————

1.58 – log (WOB / BS )

a = 0.93 Z²+ 6 Z+ 1

0.31(FBW)²+ 3(FBW) + 1

Z = X * 〔 ———————————– 〕

0.31X²+ 3X + 1

X = (Depth – Initial Depth ) / Bit Run

FBW = final bit wear (initially estimated and later corrected)

P = Tooth wear exponent (.4 to .6 for insert bits, .8 to 1 for tooth bits)

Calculating formation pressure from Dcs

Three methods are commonly used in calculation of pore pressure from Dcs:

1. Equivalent depth method

2. Ratios Method

3. Eaton Method

These are discussed in “Quantitative Methods of Real-Time Pore Pressure and Wellbore Stability Detection”.

Setting ‘d’ Exponent Trend

Trend Line (dcn): line joining dcs points in zones of normal pore pressure.

Formation Pressure is calculated from extent of diversion from normal trend.

Set the trend in shale only. Select good clean shale section. Avoid silty, calcareous, pyritic shale

Avoid using trend values where drilling conditions exist that affect ROP, such as balled up bit, pump problem, mud loss zones, coring controlled drilling, etc.

Upper unconsolidated section should not be considered for trend setting.

Once trend is set do not change the slope.

To understand the importance of the trend position, you must know that a calculation of the Formation pressure can be made based on the distance between the Dc curve and its normal trend Dcn. Roughly, the Pf curve is a “mirror image” of the distance between Dc and Dcn.

In this case above, we can see that some points of the Pf curve go over the MW curve, but these points correspond to sandy zones, and are not to be considered. Only the red dotted line (passing through the shale points Pf) is important and is used as reference for MW selection.

If the trend is set to the sand reference points (left part of the Dc curve), the formation pressure (Pf) curve is shifted to the left. In this case, the formation pressure will not be calculated accurately and the actual Pf will be over the MW before we can detect it.

Are we sure that a deflection of the Dc corresponds to an overpressure ?

If we have a shale gradually grading to a sand, the Dc will have a deflection towards the left; this can be mistaken for the start of a transition zone. Thus it is important to refer to the lithological column when evaluating the change.

With computerized plotting of Dc, we can introduce a ‘sand line’ cut off to eliminate this effect. Dc values to the left of the cutoff are ignored when pressures are calculated.

If we compare the lithographic column and the Dc, we note that the trends in the shale and in the sand are parallel, there is only a shift. This shows the importance of the cuttings analysis, which is fundamental for the Dc interpretation.

Other drilling parameters for real time pore pressure detection

Torque increase: The swelling of clay cause a decrease in hole diameter, accumulation of large cuttings or caving on the bit and stabilizers, all these problems are linked to negative differential pressure (MW too low).
Overpull and drag increase : for the same reason that causes the torque to go up.
Hole filling increase : Caving may fill the hole during tripping.
Pit level increase: In case of kick
Flow output increase : In case of kick
Pump pressure decrease: In case of kick, the annulus is filled with mud and light fluid (i.e. gas), so the pressure losses in the annulus will be less than with a complete column of mud.

MUD LOGGING LAGGED METHODS OF REAL-TIME PORE PRESSURE DETECTION

Indications from Gas:

Connection GAS: A good indicator of an increase of pore pressure is the gas “sucked” from the formation during a trip or a pipe connection (by swabbing).

The problem with this method is that it depends on the velocity of the hook when the string is pulled up; two different drillers will give two different pipe connection gases.

A much better system is to check the “Pump off Gas”: the driller stops the pumps without moving the string, so there is no swabbing. But you lose the pressure losses in the annulus; the equivalent mud weight in hole drops from ECD to MW. In that case, a gas show means that the differential pressure is close to being negative.

Check also the gas ratios! If you have more heavy gases (ie C2/C3 is decreasing), you enter a transition zone.

Background gas and peaks

Check for a. Lithology, b. ROP, c. Flow d. other aspects

Trip Gas

Check swabbing conditions (overpull, balled up bit, etc )

Swabbing: Produced gas that enters hole because of suction. This can occur due to:

1. High viscosity of mud.

2. Balled up bit.

3. Fast rate of pulling out.

4. Collar size too large for the hole.

5. Swelling of clays

6. Insufficient cutting transport.

Surging: Injection effect – mud is pushed into the formation. This can occur due to fast rate of running in, and other aspects as above.

Gas Composition: Increased proportion of heavier gasses in transition zone may be indicative of abnormal Pressure. High pressure in zone permits expulsion of lighter gasses; heavier gas are retained. Light to heavy gas ratio shows decrease. C2 / C3 ratio is often used for the purpose. C2 / C3 ratio decrease indicates over-pressure.

Gas Cut mud:

Mud gas is an important indicator of the abnormal pore pressure in drilling operations, particularly in shale formations because of lack of good methods to measure the pore pressure in the shale. If large amounts of formation gas flow into the wellbore, the downhole mud weight is reduced because of the nature of low density of gas. This is “gas cut mud,” indicating that the actual density of the mud coming out of the hole is less than the density of the mud being pumped into the hole. If the gas influx is large, the gas cut mud can cause a marked reduction of the downhole mud weight, and this could result in a gas kick or blowout. Therefore, the gas cut mud is an important indicator of the abnormal pore pressure. Intermediate circulation should be given to degas mud.

INCREASE IN BACK GROUND GAS (BG ) DUE TO CAVING: Gas in isolated pore spaces of shale is under pressure. In trying to escape it forms curved fractures in the shale near wall of hole. The chip then falls in the hole releasing some gas in the process. This leads to increase in BG.

Hydrostatic pressure of mud column < formation pressure: increase in BG due to caving and gas diffusion from low permeability beds (poor quality mud cake)

Variations in differential pressure will affect the gas recovered at surface. Low differential pressure (low overbalance) between mud hydrostatic pressure and formation pressure will give high gas reading while high differential pressure (high overbalance) will give low gas reading.

Mud Weight : An influx with salted water will make the mud density decrease.

Mud temperature: The formation temperature gradient will increase in an undercompacted zone. Measuring mud temperature does not give a precise idea of the formation temperature as all actions at surface (new mud, water adding, mixing, trips) will modify the mud temperature. Remember also that the mud has a cooling effect on the bit!

Mud resistivity: An influx with salted water has a good electrical conductivity and so the resistivity decreases.

Mechanism generating cavings under overpressure conditions

General rule is that the insufficient mud weight produces more and larger cuttings. There are generally four types of cuttings—normal cuttings, cuttings from pre-existing fractures, cuttings owing to underbalanced drilling, and cuttings owing to shear failures.

Normal Cuttings. If the mud weight is appropriate, that is, higher than pore pressure and collapse pressure but lower than the fracture gradient, the wellbore is in a good condition. In this case, normal cuttings are generated with PDC cutting marks when a PDC bit is used, as shown below

Cuttings from Pre-existing Fractures. In a formation with preexisting fractures or in a faulted section, the rock may have a lower compressive strength and lower fracture gradient. In this case, it may generate blocky cuttings in which the naturally fractured planes may be observed; therefore, mud losses probably occur in the preexisting fractures.

Cutting from pre-existing fracture or faulted section

Cuttings Owing to Underbalanced Drilling: If the downhole mud weight is less than the formation pore pressure gradient, the wellbore experiences splintering failure or spalling. In this case, spiky and concaved cavings are generalized, as shown in Figure below.

Cuttings Owing to Shear Failures: Shear failures cause angular or splintered cavings in the wellbore, a case of lower mud weight than the shear failure gradient. as shown below:

Shale density

Plotting shale density (ie using a microsol) versus depth can show an undercompaction. Direct measurement of shale density can be a primary indicator of undercompaction, but several factors limit its usability in the field.

Methods:

1. Variable Density Column: two miscible liquids are mixed to form a column; calibrated with glass beads of different densities.

2. Dense Liquors: series of flasks with fluids of increasing density.

3. Microsol: measurement of cuttings weight in air and weight in water.

4. Mud Balance: measurement of cuttings weight in air and weight in water.

5. Pycnometer: measurement of cuttings weight in air and weight in water.

Limitations of Shale Density

1. Clay must be consolidated for accurate measurement

2. Accessory minerals, carbonate content influence density:

Given shale density 2.28

Add water filled porosity 15% + 10% pyrite = Density 2.52

3. Caving -not representative of depth.

4. Water-based mud: smectite group of clays adsorb water from mud.

Thus selection of cuttings is difficult, reducing measurement is not always accurate

Mud losses

Mud losses (indicates that differential pressure is too high). If mud losses or lost circulation is observed, it normally indicates that the applied mud weight is higher than the fracture gradient (excluding mud losses into open fractures or vuggy zones), therefore, it may need to reduce the mud weight. When the hole ballooning (borehole breathing) occurs, it normally indicates that the mud weight is very close to the fracture gradient.

What is Borehole ‘Breathing’?

The phenomenon of slow mud losses while drilling ahead followed by mud returns after the pumps have been turned off.
Borehole Breathing is also referred to as ‘ballooning’ or ‘loss/gain’.

What causes Borehole Breathing?

Generally accepted idea is that the phenomenon of breathing is due to fractures being opened and closed by annular pressure fluctuations resulting from mud circulation and non-circulation. The effect of pressure increase is due to Equivalent Circulating Density (ECD).
Lowering of the Fracture Gradient due to use of mud coolers may be a cause of breathing.

Why is it important to recognize breathing?

Borehole breathing has often been mistaken in the field for an influx of formation fluid. This can lead to the wrong decisions being made with very costly consequences.

How do you distinguish between ‘Breathing’ and a Formation Influx?

Mud losses while circulating are required for ballooning to occur. Check for small continuous losses while drilling.

LWD / MWD (Shale Resistivity Log)

Resistivity of shale depends on porosity, fluid content and fluid salinity. Under normal compaction and identical environmental conditions, resistivity of shale increases with depth (less fluid content = less conductivity). Thus an abrupt decrease in resistivity is indicative of under-compaction.

Wire line/ LWD conductivity data is generally converted to resistivity. If conductivity plot is available, it will show increased conductivity in an abnormally pressured section.

LWD / MWD (Sonic Transit Time Log)

Sonic transit time is expressed in microseconds per foot.

Interval transit time is given by the equation:

⧍t = ∅⧍t _f + (1 – ∅) ⧍t_m

Transit time is small in matrix and large in fluid.

Methane= 650

Water = 170 -220

Oil = 238

Quartz = 55.5

For a given lithology transit time will depend on porosity.

Sonic transit time varies with porosity (except when free gas is present). Transit times are faster in the matrix (approx. 40-55 μsec/ft) than in the pore fluids (200 μsec/ft for water). Thus in a transition zone, average transit time will remain steady or increase.

Talk to us for your upcoming Pore-Pressure and Wellbore-Stability Prediction requirement

Geodata Evaluation & Drilling LTD. Pore Pressure consultants use specialist software to provide pore pressure profiles for your wells which are calibrated to offset well behavior for determination of optimum mud weight window for successful drilling operation. Contact us at www.geodatadrilling.com Phone: +234 8037055441

Methods of killing a well after a kick

December 22, 2020 / GEDLblogger / 0 Comments

Killing a well or controlling a kick is stopping a well from flowing or having the ability to stop formation fluid (gas, oil or water) to flow into the wellbore. Kill procedures typically involve circulating reservoir or formation fluids out of the wellbore or pumping higher density mud into the wellbore, or both.

What is a Kick

Kick is defined as an undesirable influx of formation fluid into the wellbore. If left unchecked, a kick can develop into a blowout (an uncontrolled influx of formation fluid into the wellbore). The result of failing to control a kick leads to lost operation time, loss of well and quite possibly, the loss of the rig and lives of personnel.

Warning signs of a kick

Warning signs and possible kick indicators can be observed at the surface. Each crew member has the responsibility to recognize and interpret these signs and take proper action. All signs do not positively identify a kick; some merely warn of potential kick situations. Key warning signs to watch for include the following:

Flow rate increase

An increase in flow rate leaving the well, while pumping at a constant rate, is a primary kick indicator. The increased flow rate is interpreted as the formation aiding the rig pumps by moving fluid up the annulus and forcing formation fluids into the wellbore.

Pit volume increase

If the pit volume is not changed as a result of surface-controlled actions, an increase indicates a kick is occurring. Fluids entering the wellbore displace an equal volume of mud at the flowline, resulting in pit gain.

Flowing well with pumps off

When the rig pumps are not moving the mud during flow check, a continued flow from the well indicates a kick is in progress. An exception is when the mud in the drill pipe is considerably heavier than in the annulus, such as in the case of a slug.

Pump pressure decrease and pump stroke increase

A pump pressure change may indicate a kick. Initial fluid entry into the borehole may cause the mud to flocculate and temporarily increase the pump pressure. As the flow continues, the low-density influx will displace heavier drilling fluid and the pump pressure may begin to decrease. As the fluid in the annulus becomes less dense, the mud in the drill pipe tends to fall and pump speed may increase.

Other drilling problems may also exhibit these signs. A hole in the pipe, called a “washout,” will cause pump pressure to decrease. A twist-off of the drillstring will give the same signs. It is proper procedure, however, to check for a kick if these signs are observed.

Improper hole fill-up on trips

When the drillstring is pulled out of the hole, the mud level should decrease by a volume equivalent to the removed steel. If the hole does not require the calculated volume of mud to bring the mud level back to the surface, it is assumed a kick fluid has entered the hole and partially filled the displacement volume of the drillstring. Even though gas or salt water may have entered the hole, the well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure.

String weight change

Drilling fluid provides a buoyant effect to the drill string and reduces the actual pipe weight supported by the derrick. Heavier mud have a greater buoyant force than less dense mud. When a kick occurs, and low-density formation fluids begin to enter the borehole, the buoyant force of the mud system is reduced, and the string weight observed at the surface begins to increase.

Drilling break

An abrupt increase in bit-penetration rate, called a “drilling break,” is a warning sign of a potential kick. A gradual increase in penetration rate is an abnormal pressure indicator, and should not be misconstrued as an abrupt rate increase.

When the rate suddenly increases, it is assumed that the rock type has changed. It is also assumed that the new rock type has the potential to kick (as in the case of a sand), whereas the previously drilled rock did not have this potential (as in the case of shale). Although a drilling break may have been observed, it is not certain that a kick will occur, only that a new formation has been drilled that may have kick potential. It is recommended when a drilling break is recorded that the driller should drill 3 to 5 ft (1 to 1.5 m) into the sand and then stop to check for flowing formation fluids. Flow checks are not always performed in top hole drilling or when drilling through a series of stringers in which repetitive breaks are encountered. Unfortunately, many kicks and blowouts have occurred because of this lack of flow checking

Cut mud weight

Reduced mud weight observed at the flow line has occasionally caused a kick to occur. Some causes for reduced mud weight are: Core volume cutting, Connection air, Aerated mud circulated from the pits and down the drill pipe

Fortunately, the lower mud weights from the cuttings effect are found near the surface (generally because of gas expansion), and do not appreciably reduce mud density throughout the hole.

An important point to remember about gas cutting is that, if the well did not kick within the time required to drill the gas zone and circulate the gas to the surface, only a small possibility exists that it will kick. Generally, gas cutting indicates that a formation has been drilled that contains gas. It does not mean that the mud weight must be increased.

Primary well control

Primary well control is the process of maintaining hydrostatic pressure in the wellbore greater than the formation pressure being drilled, but less than formation fracture pressure. If hydrostatic pressure is less than formation pressure then formation fluids will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the fracture pressure of the formation then the fluid in the well could be lost. In an extreme case of lost circulation the formation pressure may exceed hydrostatic pressure allowing formation fluids to enter into the well.

Secondary well control

Primary well control failed when the hydrostatic pressure in the well (i.e. drilling mud) fail to prevent formation fluids from entering the wellbore. Therefore, a secondary well control is introduced with special equipment called “Blow Out Preventer” or BOP to control unwanted formation fluids in the wellbore.

**Choke manifold (Source: Cameron Iron Works)**

In order to control a kick, mud of the required density must be added and circulated while back pressure is maintained against the formation. This excess pressure must be slightly higher than the pressure of the fluids contained in the pores of the formation.

There is therefore a need for a line, the choke line, between the annulus and a manifold which directs the effluent to one of the following, depending on the type of fluid involved: mud tanks, degasser, flare, reserve pit

Methods of killing a well

Common circulating well methods of killing a well or well control techniques are:

Driller’s method
Wait and Weight
Concurrent

These all use the same procedures and only differ when and if a kill weight fluid will be circulated.

Volumetric Method & Lubricate and Bleed
Reverse Circulation
Bullheading

The Driller’s Method Procedure

Shut-in well after kick: Close the annular preventer of Blow out Preventer (BOP). Open HCR valve (Hydraulically control remote valve) to the choke manifold.
Record kick size and stabilized shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP).
As soon as possible start circulating original mud (fluid) by gradually bringing the pump up to the desired kill rate while using the choke to maintain constant casing pressure at the shut-in value.
Pump pressure should be equivalent to calculated initial circulating pressure (ICP). If not equivalent, investigate and recalculate if necessary.
Maintaining pump pressure equal to ICP, kick/influx is circulated out of the well, adjusting pressure with choke as required. After Kick Circulated Out –Killing The Well:
Continue to circulate from an isolated pit or slowly shut down the pump maintaining pressure on the choke (casing) gauge equivalent to the original SIDPP.
Avoid trapping pressure or allowing additional influx if shutting back in – Avoid trapping pressure or allowing additional influx if shutting back in.
The active system should be weighted up to the pre-determined kill fluid density and circulated in order to regain hydrostatic control.
If the well was shut in, startup pump procedures are again used.
It is advisable to calculate and use a pressure vs. stroke chart (ICP to FCP – final circulating pressure) to track the kill fluid and changes in circulating pressures.
Circulate the kill fluid to the bit/end of string.

After Kick Circulated Out –Killing The Well:

Once kill fluid is at the bit/end of string, FCP should be realized.
Circulating pressure should be equivalent to the calculated FCP.
Maintain constant FCP circulating pressure until the kill fluid completely fills the well.
The gain in hydrostatic pressure (HP) should necessitate slowly reducing choke pressure.
Once the kill fluid reaches surface, the choke should have been fully opened.
Shut down pump and check for flow.
Close choke and check pressures.
If no pressure is noted, open choke (bleeding any trapped pressure), open BOP.

Wait and Weight Method Procedure

Shut-in well after kick. Close the annular preventer of Blow out Preventer (BOP). Open HCR valve (Hydraulically control remote valve) to the choke manifold.

2. Record kick size and stabilized SIDPP and SICP, calculate kill fluid density.

3. Pits are weighted up as other calculations are performed.

4. If there are increases in shut-in pressure, the Volumetric Method should be used to bleed off mud/fluid from the annulus to maintain constant stabilized drill pipe/tubing pressure.

5. Once pits are weighted, start circulating kill weight fluid by gradually bringing up the pump up to the kill rate while using the choke to maintain constant casing pressure at the shut-in value. Remember to hold pump rate constant.

6. Circulating pressure should be equivalent to (ICP) Initial Circulating Pressure. If not, investigate and recalculate ICP if necessary.

7. Follow pressure chart/graph as kill fluid is pumped down the string to bit/end of string.

8. Once kill fluid is at the bit/end of string, FCP should be realized.

Circulating pressure should be equivalent to the calculated FCP.

9. Maintain constant FCP circulating pressure until the kill fluid completely fills the well.

The gain in HP should necessitate slowly reducing choke pressure.
Once the kill fluid reaches surface the choke should have been fully opened.

10. Shut down pump and check for flow.

11. Close choke and check pressures.

12. If no pressure is noted, open choke (bleeding any trapped pressure), open BOP.

Concurrent Method

Sometimes referred to as the Circulate and Weight Method or Slow Weight-Up Method. It involves gradually weighting up fluid while circulating out the kick.

Additional calculations are required when tracking different fluid weights in the string at irregular intervals.

Sometimes, crew members are required to record concurrent method data even if this is not the method intended to be used.

The Concurrent Method Procedure:

Shut-in well after kick. Close the annular preventer of Blow out Preventer (BOP). Open HCR valve (Hydraulically control remote valve) to the choke manifold.

2. Record kick size and stabilized SIDPP and SICP.

3. ASAP start circulating original mud (fluid) by gradually bringing the pump up to the desired kill rate while using the choke to maintain constant casing pressure at the shut-in value.

Pump pressure should be equivalent to calculated ICP. If not equivalent, investigate and recalculate if necessary.

4. Mixing operations begin and pits are slowly weighted up and each unit of heavier fluid reported.

5. Each interval or unit of increased fluid density is then noted and recorded with the pump stroke count at that time.

The change in circulating pressure for the different density is calculated.
Once this fluid reaches the bit/end of tubing, circulating pressure is adjusted with the choke by that amount.

6. The kick is circulated out and the fluid in the well continues to be gradually increased.

7. Once the kill fluid is consistent throughout the well, shut down pump and check for flow.

8. Close choke, shut well in and check pressures.

9. If no pressure is noted, open choke (bleeding any trapped pressure), open BOP.

Volumetric Method of Well Control

The volumetric method is a way of allowing controlled expansion of gas during migration

It replaces volume with pressure (or vice versa) to maintain bottom hole pressure that is equal to, or a little higher than BHP, and below the formation fracture pressure.

With a swabbed in kick, the volumetric method can be used to bring influx to surface and then replace the gas with fluid in order to return the well to normal hydrostatic pressure. It is not used to weight up and kill the well.

Used to control the well until a circulating method can be implemented.
Can be used to regain HP if the existing fluid is adequate and gas is allowed to reach surface.

Situations where Volumetric Methods can be used:

String is plugged.
String is out of the hole.
Pumps are not working.
String is off bottom.
During stripping or snubbing.
A shut-in period or repairs to surface equipment.
Tubing or packer leak causes casing pressure to develop on production or injection well.
A washout in string prevents displacement of kick by one of the circulating methods.
In subsea operations only 1 line should be used to prevent gas separation effects.

If casing pressure does not increase 30 minutes after a kick is shut in, gas migration is minimal. This means that the Volumetric Method need not be used. However, if casing pressures continues to increase there is a need to initiate Volumetric techniques.

Some basic scientific principles must be understood before using the Volumetric Method:

Boyle’s Law–shows the pressure/volume relationship for gas. It states that if gas is allowed to expand, pressure within the gas will decrease. This is the same concept used by the Volumetric Method in that it allows gas to expand by bleeding off an estimated fluid volume at surface, which results in decreasing of wellbore pressures.

Boyle’s LawP1 V1 = P2 V2

Single Bubble Theory–The biggest misconception in well control schools is that the gas enters the well as a “single bubble”.

In reality it is dispersed as pumping and observance of the kick is noted, then more “pure” kick as the pumps are shut down and well is shut in.
It may be many minutes before the kick is actually noted resulting in an annulus filled with influx/regular fluid.
So, in reality, a single large kick rarely occurs, and once the well is shut in, the pressures on the casing shoe/weak zone have probably reached it’s maximum.
This is not to say that MAASP should not be observed, just that it should be considered that the maximum pressure should be based on the latest pressure test of the BOP or casing.

Stripping/Moving Pipe and Volumetric Considerations

A stripping pressure schedule must be created in order to control pressures during stripping operations while gas is migrating, pipe is moving, and fluid is being bled off at choke.

Lubricate & Bleed (Lubrication)

 The Lubricate & Bleed Method is used when kick fluid reaches the wellhead.

 It is considered a continuation of the Volumetric Method.

 Generally, workover operations more commonly use the Lubricate and Bleed technique because circulating ports in the tubing are plugged, sanded tubing, or circulation is not possible.

Lubricate & Bleed (Lubrication)

 In this method, fluid is pumped into the well on the annulus side.

 Enough time must be allowed for fluid to fall below gas.

 Volume must be precisely measured so hydrostatic pressure gain in the well can be calculated.

 This value increase will then be bled off at surface.

Reverse Circulation Method of Well Control

 Reverse circulation is the reversal of normal circulation or normal well kill pump direction.

 In reverse circulation, due to friction (APL, ECD) most of the circulating pump pressure is exerted on the annulus.

 Standard start up procedures apply.

Advantage

1. It is the quickest method of circulating something to the surface.

2. Gets the problem inside the strongest pipe from the beginning.

3. Generally, the annular fluid is dense enough to maintain control of the formation, which reduces fluid mixing and weighting requirements.

Disadvantage

1. Higher pressure is placed on formation and casing.

2. Excessive pressure may cause fluid losses/casing and/or formation failures.

3. Not applicable for uses where plugging of circulating ports, bit nozzles of string are possible.

4. Gas filled or multiple densities in tubing may present problems establishing proper circulating rates.

Bullheading Method of Well Control

 Bullheading, or deadheading, is often used as a method of killing wells in workover situations.

 Bullheading is only possible when there are no obstructions in the tubing and there can be injection in the formation without exceeding pressure restraints.

 Bullheading involves pumping back well fluid into the reservoir, displacing the tubing or casing with a good amount of kill fluid.

Complications can make bullheading difficult in certain situations:

– Sometimes, when bullheading down the tubing, pressure may have to be exerted on the casing in order to prevent the tubing from collapsing. Both, tubing and casing burst/collapse pressures, should be known and not exceeded.

– Formation fracture pressure may have to be exceeded due to low reservoir permeability

– Gas migration through the “kill fluid” can pose a problem. In this situation, viscosifiers should be added to the kill fluid to minimize the effect of migration.

Bullheading Procedure

1. Well is shut in and formation pressure is calculated. If bullheading down the tubing, maximum pressures should be calculated.

2. Prepare a rough pressure chart of volume pumped versus maximum pressures at surface. Friction and formation pressure must be overcome to achieve injection of the liquid in the tubing back into the formation. If pressures or pump rate is too high, damage to the formation may occur.

3. Once the pumped liquid reaches the formation, an increase in pump pressure may occur. This is due to a non-native fluid injected to the formation.

4. Once the calculated amount of fluid is pumped, shut down, observe pressures. If no pressure increase is observed, bleed off injection pressure and, again, observe. If no pressure change is seen, the well should be dead. Proceed operations with caution.

How to Spot Potential water pollution Problems?

December 9, 2020 / GEDLblogger / 12 Comments

The potential for pollution entering your well is affected by its placement and construction — how close is your well to potential sources of pollution? Local industrial activities, your area’s geology and climate also matter.

The best way to identify potential contaminants is to consult a local expert. For example, talk with a geologist or someone from a nearby public water system.

Borehole location to the source of water pollution

Have Your Borehole Water Tested

Test your water every year for total coliform bacteria, nitrates, total dissolved solids, and pH levels. If you suspect other contaminants, test for these also. Chemical tests can be expensive. Limit them to possible problems specific to your situation. Again, local experts can tell you about possible impurities in your area.

Before taking a sample, contact a water treatment company like ours. We will follow the procedure to collect the water sample and liaise with the lab that will perform the water tests.

Remember to test your water after replacing or repairing any part of the well system (piping, pump, or the well itself.) Also test if you notice a change in your water’s look, taste, or smell.

The chart below (“Reasons to Test Your Water”) will help you spot problems. The last five problems listed are not an immediate health concern, but they can make your water taste bad, may indicate problems, and could affect your system long term.

Reasons to Test Your Water

Conditions or Nearby Activities:	Test for:
Recurring gastro-intestinal illness	Coliform bacteria
Household plumbing contains lead	pH, lead, copper
Corrosion of pipes, plumbing	Corrosion, pH, lead
Nearby areas of intensive agriculture	Nitrate, pesticides, coliform bacteria
Coal or other mining operations nearby	Metals, pH, corrosion
Gas drilling operations nearby	Chloride, sodium, barium, strontium
Dump junkyard, landfill, factory, gas station, or dry- cleaning operation nearby.	Volatile organic compounds, total dissolved solids, pH, sulfate, chloride, metals
Odor of gasoline or fuel oil, and near gas station or buried fuel tanks	Volatile organic compounds
Objectionable taste or smell	Hydrogen sulfide, corrosion, metals
Stained plumbing fixtures, laundry	Iron, copper, manganese
Salty taste and seawater, or a heavily salted roadway nearby	Chloride, total dissolved solids, sodium
Scaly residues, soaps don’t lather	Hardness
Rapid wear of water treatment equipment	pH, corrosion
Water softener needed to treat hardness	Manganese, iron
Water appears cloudy, frothy, or colored	Color, detergents

Water pollution problem and what to test for

Understanding Your Test Results

Have your well water tested for any possible contaminants in your area. Do not be surprised if a lot of substances are found and reported to you.

The amount of risk from a drinking water contaminant depends on the specific substance and the amount in the water.

The health of the person also matters. Some contaminant cause immediate and severe effects. It may take only one bacterium or virus to make a weak person sick. Another person may not be affected. For very young children, taking in high levels of nitrate over a relatively short period of time can be very dangerous.

Many other contaminants pose a long-term or chronic threat to your health — a little bit consumed regularly over a long time could cause health problems such as trouble having children and other effects.

The amounts of contaminants allowed are based on protecting people over a lifetime of drinking water. Public water providers – (Package and bottle water) are required to test their water regularly before delivery. They also treat it so that it meets drinking water standards, notify customers if water does not meet standards and provide annual water quality reports.

Compare your borehole water test results to WHO or federal and state drinking water standards and water treatment solution offers by a company like ours will design a water treatment plant to rectify your water contaminant or pollution problem.

Well Construction and Maintenance

Proper well construction and continued maintenance are keys to the safety of your water supply. Our company, a water- well contractor can provide information on well construction.

Take a look at the following graphic illustration of well locations and how surface water drains to guard against water pollution.)

Talk to us for your upcoming water borehole construction and treatment requirement

Geodata Evaluation & Drilling LTD. offers borehole construction, maintenance and water treatment services. For your water services requirement. contact us at www.geodatadrilling.com Phone: +234 8037055441

Drinking Water Problems and Water Treatment solutions

November 28, 2020 / GEDLblogger / 0 Comments

Water is a simple chemical compound. The chemical formula of water is H2O. That is, each water molecule consists of one oxygen atom between two hydrogen atoms. Water is indispensable for human health and well-being; there can be no life on Earth without water. The human body is composed of 70% water. However, that same water could be hazardous to your health if not treated and purified. Untreated water contains turbidity, iron, manganese, high level of calcium and magnesium, nitrate, total dissolve solids (TDS), tannin, bacteria etc.

Why water treatment is so important?

Water is found almost everywhere on Earth. Water resources like underground water, rivers, lakes, which provide water contain a lot of pollution and contamination unfit for consumption. To be clean, the water should undergo a number of treatments necessary to make it drinkable. Water treatment and purifiers are designed to eliminate or reduce certain pollutants (nitrates, pesticides, heavy metals, organic materials etc.), as well as improve the quality taste of water.

Drinking untreated or unfiltered water can be harmful to the body. World Health Organization (WHO) published a list of WATERBORNE DISEASES that can affect people all over the world: diarrhea disease, Hepatitis A, Cholera, Botulism, Typhoid, Dysentery, Polio, etc.

Water treatment solutions to common water problems

Colour

There are many factors that may cause colour in water. The most common causes are iron, manganese, tannins, organic matter, and/or colloidal solids that are too small and too fine to settle out properly.

If the color is from tannin or humic acids, then a tannin filter might be applicable. These filters remove dissolved color by ion-exchange, using anion exchange media. The units use regenerate with rock salt (sodium chloride). While these are called tannin filters, they are really ion-exchange units.

Sometimes tannin are accompanied with iron or manganese. Water high in iron or manganese can sometimes be red, rust coloured, brown, tan, black, or greenish in colour. Oxidation, followed by a well-designed iron filter can be very effective at removing tannin and these oxidized iron particles.

Turbidity (Cloudy)

There are many factors that may cause cloudy or turbid water. Cloudy water can also be referred to as having high levels of turbidity. The most common causes of turbidity are organic matter, colloidal solids that are too small and too fine to settle out properly. These suspended particles can cause problems with disinfection processes and also an indicator of bacterial activity in the water. Turbidity is measured in NTU’s, (Nephelometric – Turbidity Units). The turbidity of drinking water should always be less than 1 NTU.

A very effective method to remove turbidity is with reverse osmosis (‘RO”) or ultrafiltration (“UF”) membrane systems. RO and UF systems can be used by homeowners, small communities and commercial sites to reduce turbidity and produce crystal clear water less than 0.1 NTUs. Another low cost option is to use a whole house cartridge filter. These filters are large size filter cartridge systems which come in various micron ratings and can filter down to the 1 micron size. One option frequently used by homeowners with cloudy water is to use a back-washing sediment filter, followed by a 1 or 5 micron filter cartridge system

Iron and Manganese

Iron and manganese are often found in a dissolved state in well waters, and the water appears clear when first drawn. Upon exposure to air, or after the addition of oxidants (such as chlorine bleach or ozone), this ferrous iron is oxidized (“rusted”) to the ferric state to form insoluble particles. The water then looks orange or yellow, or in the case with manganese, brown or black.

The role of pH is very important in iron treatment. Generally, if the pH of the water is acidic (or less than 7.0), it must be corrected with a special type of neutralizing filter of the iron filtration system. It is usually best to test for pH right at the water source, and not depend on laboratory analysis for pH, since in some cases the pH can raise after sampling, giving false results.

Hard Water

The term “water hardness” originally referred to the ability of water to precipitate soap and form soap scum. Soap is precipitated (or brought to the “surface”) by water containing high levels of calcium and magnesium. The “harder” the water the less soap will dissolve in the water.

The most common mechanical way to soften water is through the use of an ion exchange water softener. This device uses an ion exchange process to replace hardness minerals in the water with another substance. The vast majority of water softening equipment today exchanges hardness minerals for sodium. The process consists of flowing the hard water over a bed of plastic resin beads. On each bead, slight electric charges hold sodium ions on the surface of the bead. However, these beads also have the ability to attract and hold hardness minerals. As hard water flows through the water softener, it passes around the plastic beads. The hardness minerals (ions) in the water have a greater attraction to the bead than the sodium on the bead. Therefore, they attach themselves to the bead, and in the process they displace the sodium ions. Thus the name ion exchange.

Odour

In well water, odours are commonly the result of sulfur bacteria, or compounds of iron, manganese, and sulfates. For example, hydrogen sulfide gas (“rotten-egg odour”) commonly occurs in well water as a result of decaying organic matter and the activity of sulfates and various species of sulfur or iron bacteria.

Plumbed-in activated carbon filters work on the same principle as the jug filter to remove chlorine and organic substances but are not so effective on inorganic such as salts and metals. They consist of a filter head for connection to the water supply with a detachable bowl housing a filter cartridge incorporating a mechanical filter, which excludes grit, dirt, sand and so on.

The effectiveness of an activated carbon filter can be extended through additions to the basic filter material and different types of cartridge are now available, capable of removing or reducing a variety of additional substances. Activated carbon filters are also often used as the main element of a larger combination filter system, capable of removing heavy metals and nitrates.

Bacterial growth can occur in filters if they are left unused for a long period of time, as they would be, for instance, at a holiday home. Any treated water not used immediately should be refrigerated.

All filter cartridges should be changed regularly, in accordance with the manufacturer’s instructions. The maximum filter cartridge life recommended by BRITISH WATER is 6 months for standard filters

Nitrate

The primary causes of nitrate contamination in groundwater are failed or overloaded or improperly constructed and located septic systems, animal waste and fertilizer. Water that comes in contact with these sources will absorb nitrate and carry it down into the soil eventually ending up in the groundwater.

If a consumer chooses to reduce nitrate levels, there are several plumbed-in drinking water filters available to do the job. Be aware, though, that there are many types of drinking water filters available, with different capabilities and only some will remove or reduce nitrate.

Total dissolved solids (TDS)

TDS is the term used to describe the inorganic salts and small amounts of organic matter present in solution in water. The principal constituents are usually calcium, magnesium, sodium, and potassium cations and carbonate, hydrogencarbonate, chloride, sulfate, and nitrate anions.The higher the TDS, the less palatable the water is considered to be. TDS affects affect taste, TDS of over 500 – 600 ppm can have an alkaline taste

When the level of TDS exceed 1500 ppm, most people start to complain of dry skin, stiff laundry, and rapid corrosion of piping and fixtures. White spotting and films on surfaces and fixtures is also common.

TDS is removed by distillation, reverse-osmosis or electrodialysis. Increasingly most desalination projects, both large and small are accomplished with reverse-osmosis. Depending on the water chemistry, reverse osmosis systems are the most popular, given their low cost and ease of use.

Tannin

Tannins are natural organic materials that are usually the by-products of the natural break down of decaying vegetation and sometimes the product of “natures” fermentation process as opposed to the tannins found in wines. They are created as water passes through peaty soil and decaying vegetation. This causes the water to have a faint yellow to tea-like color, and can cause yellow staining on fabrics, fixtures, china and laundry. Tannin may give an unpleasant aftertaste to water. It may also cause water to have a musty or earthy odor. Tannins are sometimes referred to as fulvic or humic acids and are more common in surface water supplies, lake or river sources and shallow wells than in deep wells. Water in marshy, low-lying, or coastal areas is also more susceptible to tannins.

Tannin can be removed by tannin filters. These filters remove tannin by ion-exchange, using anion exchange media. The units we use regenerate with rock salt (sodium chloride) in the same way water softeners function. Frequently we see shallow wells under the influence of surface run-off water, achieve high levels of tannin (turning the water brown) during heavy rains periods. Tannin filters are often an excellent relatively low-cost technology to use for this type of problem.

A very effective method to remove tannin colour is by using ultrafiltration (“UF”) membrane systems. UF systems can be used by homeowners, small communities and commercial sites to reduce turbidity and produce crystal clear water less than 0.1 NTUs.

Low PH

Water with a pH lower than 7 is considered acidic. This can cause many problems in your home, such as damage to your plumbing and water-using appliances, blue-green staining, and poor-tasting water. If you think your home has an acidic water problem, the following overview will help you to identify acidic water signs, and learn how to test, treat and neutralize your home’s water.

Signs of Acidic Water

Damage: When your home’s water has a low pH, this can cause damage to your plumbing and water-using appliances. Typically, acidic water damage first shows up as a blue-green build-up around pipe fittings. These eventually lead to pinhole leaks in piping, which can cause water damage within your walls.
Staining: If you see blue-green staining around your fixtures or on your laundry, this could be due to acidic water. To clean these areas, try mixing baking soda and white vinegar into a paste, then scrub the stained area with a nylon mesh sponge.
Odor/Taste: Acidic water can leave a metallic taste or odor in your drinking water. This can also be noticeable in water used for showering, cooking and brushing your teeth.

Treatment is accomplished by neutralizing the water with the use of a neutralizer filter. The filter uses a media in the filter which corrects the acidic nature of water without the need for mixing or dosing of chemicals. The media slowly reacts with water and the filter media is topped up, usually once a year

Bacteria

Coliform bacteria are common in the environment and are generally not harmful. However, the presence of these bacteria in well water or spring water usually indicates that the water may be contaminated with germs that can cause disease.

E. coli, is a type of faecal coliform bacteria commonly found in the intestines of animals and humans. E. coli is short for Escherichia coli. E. coli comes from human and animal wastes. The presence of E. coli in water is a strong indication of recent sewage or animal waste contamination. Sewage may contain many types of disease-causing organisms.

If the contamination is a recurring problem, try to identify the source of the problem (such as a defective well seal, or cracked casing) and fix it. You can also install a disinfection unit.

Talk to us for your upcoming water treatment requirement

Geodata Evaluation & Drilling LTD. offers water treatment services. For your water treatment requirement. contact us at www.geodatadrilling.com Phone: +234 8037055441

Pressure and overpressure formation in Well Drilling

November 19, 2020 / GEDLblogger / 0 Comments

What is pressure?

A pressure is a force divided by the surface where this force applies.

Pressure Pascal = Force Newton / Surface m²

The official pressure unit is the Pascal

It is a very small unit: 1 Pascal = 1 Newton/m²

1 bar = 105 Pascal

1 atm = 1,013 *105 Pascal

A practical unit on the rig is the kgf/cm²

1 kgf/cm² = 0.981 bar

In API , the unit is the pound per square inch (psi)

1 bar = 14.4988 psi

Hydrostatic Pressure: Ph

Pressure exerted by the weight of a static column of fluid. It is a function of fluid specific gravity and of vertical height of the fluid.

Ph = d * g * H

With Ph = hydrostatic pressure (Pascal)

d = Fluid specific gravity (kg/m³)

H = Vertical height of fluid (m)

Using well site units, the formula becomes:

Ph = H*d

With Ph= hydrostatic pressure (bar or kg/cm²)

d = Fluid specific gravity (kg/l)

H = Vertical height of fluid (m)

Note: The term 10 is approached, for precision, you should use 10.2 with pressure in bars and 9.6 for pressure in kg/cm²

In API, the formula is: Ph = 0.052 * H * d

With Ph= hydrostatic pressure (psi)

d = Fluid specific gravity (ppg)

H = Vertical height of fluid (ft)

Overburden: S

At a given depth, the overburden is the pressure (applying on fluids) or stress (applying on matrix) exerted by the weight of the overlying sediments.

S = H * ∂_b

With S = Overburden stress (kg/cm²⁾

∂_b = Formation average bulk density (no unit)

H = Vertical thickness of overlying sediments (m)

In API, the formula is:

S = H * ∂_b* 0.433

With S = Overburden stress (psi)

∂_b = Formation average bulk density (no unit)

H = Vertical thickness of overlying sediments (ft)

The bulk density of sediment is a function of the matrix density, the porosity and the density of the fluid in the pores.

∂_b= (Φ * ∂_f) + (1-Φ) * ∂_m

With ∂_b = Bulk density (no unit)

∂_f = Formation fluid density (no unit)

Φ = Porosity (from 0 to 1)

∂_m = Matrix density (no unit)

With depth, the sediment porosity will decrease under the effect of compaction (proportional to overburden) and of course, the bulk density will increase.

You will note that the porosity shale curve is exponential

FORMATION PRESSURE: Pf

Also called Pore pressure: Pp. Is Pressure of the fluid contained in the pores of the sediment

NORMAL Pf: Pf=Ph

The formation pressure (Pf) equals the hydrostatic pressure (Ph) due to the column of fluid in the sediment. It depends on the density of the water (usually from 1.00 to 1.08)

NEGATIVE Pf ANOMALY: Pf<Ph

In the following example, the outcrop is lower than the point where the well enter the formation. The water does not reach this zone.

POSITIVE Pf ANOMALY: Pf>Ph

Artesian well: In this case:

Pf = Hd /10 instead of h d / 10

Hydrocarbon column

Due to the difference of densities between water and hydrocarbons, the pressure at the top of the reservoir is almost the same that at hydrocarbon –water contact

The formula for the pressure anomaly (excess of pressure respect to normal) is:

P_hc= H * (d_w – d_hc)

With

P_hc = Pressure anomaly at the top of the hydrocarbon column (kg/cm²)

H = Height of the hydrocarbon column (m)

d_w = Water SG (kg/l)

d_hc = Hydrocarbon SG (kg/l)

Note that this anomaly is proportional to the height of the hydrocarbon column and to the difference of SG between water and hydrocarbon.

Pressure & mud weight

Equilibrium & equivalent mud weight

Equivalent Mud weight is the MW corresponding to a mud column pressure, related to depth. It represents the average mud weight needed to counterbalance formation pressure Pf

From the hydrostatic pressure (Ph) formula, we can recover:

MW = P * 10

PRESSURE GRADIENT: G

A pressure gradient G is the unit increase in pore pressure for a vertical increase in depth unit, but to get consistency with mud weight, we will take 10m.

It is used to give a degree of consistency to pressure data: Pressure gradient and mud weight will be comparable. As the figures are similar, MW and Pressure gradient may be plotted on the same graph, allowing a comparison between MW, Formation pressure gradient, Fracture gradient (fracture pressure gradient is the pressure required to induce fractures in rock at a given depth) and Overburden gradient.

As the figures are similar, MW and Pressure gradient may be plotted on the same graph, allowing a comparison between MW, Formation pressure gradient, Fracture gradient and Overburden gradient.

Stress Concept

Unlike liquids, solids can withstand different loads in various directions: Imagine a cube of porous rock somewhere in the deep. We can divide the stresses in 3 resulting forces according to the 3 directions of space: S1 can be considered as the Overburden , S2 and S3 the tectonic forces (open hole ovalization can give an idea of the difference between S2 and S3).

In a porous rock, the fluid may support part of the stress (due to undercompaction) and the total stress S will have 2 components:

S = Pp + ☌ (Terzaghi equation)

With S = Total stress (kgf/cm₂)

Pp = Pore pressure ( or formation pressure) (kgf/cm₂)

☌ = Effective stress (on the grains of the rock) (kgf/cm₂)

Consequently:

S₁ = Pp + ☌₁

S₂ = Pp + ☌₂

S₃ = Pp + ☌₃

So, in theory, the formation pressure is limited by the overburden !

Origins of Abnormal Pore Pressure or Overpressure Formation

1. Under compaction (overburden effect)

The main cause of overpressure formation.

Normally, the compaction increases with depth and the formation water is expelled as the porosity decreases. In some cases, the water cannot be eliminated in time and remains trapped in the sediment: the main cause of overpressure is due to what is called undercompacted shales. Water elimination from shale depends on 3 factors:

Clay permeability: very low
Sedimentation and burial rate: if the sedimentation rate is very high, the shale is brought very deep before the water has time to go and it remains trapped in the sediment (ie: deltaic areas)
Drainage efficiency: sand layers act as a drain and helps water elimination, less than 15% of sand content in a shale will cause a lack of drainage and an overpressured zone.

Terzaghi experiment

The springs represent the matrix, and the load on the upper plate represents the overburden.

A: the lower tap is closed (no drainage) and S is only supported by the fluid:

S = Pf

B: The lower tap is open, water escapes and the spring/matrix bears part of the load: At that stage, if you close the tap, you get something similar to an undercompacted shale: the fluid is trapped in the sediment and supports part of the overburden, causing an overpressure.

S = Pf + ☌

C: The springs/matrix fully support the load: this is the case of a normally compacted sediment.

Pf = Ph

S = ☌

2. Aquathermal expansion

The volume of water increases with temperature, if it is in a sealed environment, its pressure increases. (Actual effect is controversial.)

3. Clay diagenesis

With depth, the smectites (as Montmorillonite) will lose its adsorbed water and transform into Illite with free water. (Not really a cause of overpressure, but acts as a contributory factor in case of under-compacted shale)

4. Osmosis

Osmosis is the spontaneous movement of water through a semi-permeable membrane separating two solutions of different concentrations, until the concentration of each solutions becomes equal.

A clay bed can act as a semi-permeable membrane between two reservoir containing water with different salinity. ( Note: Not proven in nature and anyway minor effect if exists.)

5. Evaporites

Sealing role: Evaporites are impermeable and can make a good seal that will block water expelled from underlying sediment, creating overpressure by overburden effect. (Note: Major role in overpressure generation, specially if interlayed with shale.)

6. Sulfate diagenesis

Gypsum is the precipitated form of CaSO₄, transformation to Anhydrite may occur early in the burial process:

CaSO_4,2H₂O (Gypsum) D CaSO₄(Anhydrite) +2H₂O

The water amounts to 38% of the original volume, if it cannot be expelled, overpressure develops. Similar increase of volume is created by rehydration of Anhydrite. Note: Minor effect as the diagenesis of gypsum to anhydrite often occurs at shallow depth, this allows the water to escape. Rehydration of Anhydrite is not proven on a scale that would be enough to generate overpressure.

7. Organic matter transformation

At shallow depth, bacteria will transform organic matter into biogenic methane. From a depth of 250m, thermochemical cracking will transform heavy hydrocarbons to lighter ones, with increase of volume. If these processes occur in a close environment, they create overpressure. Note: Important role in overpressure generation in confined series of shaly sands or carbonate.

Tectonics

8. Relief & structuring

Relief can be the cause of pressure anomalies (ie: artesian well). An artesian well is simply a well that doesn’t require a pump to bring water to the surface. This occurs when there is enough positive pressure in the aquifer to bring the water to the surface. An artesian aquifer is confined between impermeable rocks or clay which causes this positive pressure.

9. Re-organisation of stress field

Sediments are subjected to overburden and to horizontal tectonic stresses.

10. Faults

Faults can create a seal and stop the water or on the contrary, bring an overpressured zone in front of a permeable zone, allowing the water to escape

11. Carbonate compaction

Normally, carbonates do not have problems of undercompaction. Chalk is the exception. Chalk is due to the deposit of tiny discs called coccoliths (calcareous plates protecting some phytoplankton) and Chalk structure looks like Clay structure, with the same problem of low vertical permeability.

12. Permafrost

Typical of the artic zones. The overpressure is due to unfrozen pockets (called taliks) inside the permafrost. If a talik freeze, its volume tends to increase (remember that ice is bigger than original volume of water), but the permafrost impedes expansion, thus creating overpressure.

Drilling logs in Water Borehole Drilling

November 15, 2020 / GEDLblogger / 0 Comments

The Purpose of drilling logs

In construction of borehole with a good yield of clear and clean water which is free of contaminants. A Drilled log is needed to determine the depth or location of aquifers or permeable interval for screen installation, the location of impermeable layers, location of sanitary seal above the gravel pack (which surrounds the well- screen)

A drilling log is a written record of the geological formations (soil layers) drilled, according to depth. Soil samples should be taken at regular depths (e.g. every meter) and described during the drilling process. The soil description is then recorded in the form of a drilling log. The drilling log will help to determine:

The right aquifer for installation of the well-screen
Depth and length of the well-screen
Depth and thickness of the gravel pack
Location of the sanitary seal

Hydro geological database information

Besides the direct use of drilling logs in the field, drilling logs are also very important to record the hydro geological information of the drill site. For example, if at a later stage other wells have to be drilled in the same area, it is very useful for the drilling team to know the geology, depth of the water table and likely total drilling depth. Previous drilling logs are an essential source of information for these purposes, before the new drilling starts. This information could be important for the choice of the drilling equipment. The drilling logs can be kept together in a file, which is called a database. By taking care to record and preserve good drilling logs, the drilling team will present itself as a professional and skilled team to their clients.

Taking soil sample

The first step in making a drilling log, is to take representative samples of the soil (geological formations) encountered in drilling. This means: the sample should be a pure piece of the layer that is being drilled at the moment of sampling (avoiding mixing the sample with soil from other layers!). Samples should be taken every meter and/or every time the formation (soil) type changes. The samples should be put on a plastic sheet (write down the depth if the sample is not immediately described), away from the drilling activities. Then described and recorded on the drilling log with the depth at which the soil sample was taken.

DRILLING DEPTH

The final drilling depth is reached when at least 4-6 meter has been drilled into a water bearing permeable sand or gravel layer. It is then recommended to drill two extra meters for installation of the sump which is a reservoir for particles in the borehole to settle down during the well casing installation process.

FILLING IN THE DRILLING LOGS

Step 1

Describe samples and write down the depth, name and characteristics on the drilling log.

Step 2

Then, especially important for those who can not write, hatch the formation column and show the difference between permeable, semi permeable and impermeable layers by different hatching.

Step 3

Now the well-screen length and depth can be determined.

Step 4

Once the well-screen and PVC casing are hatched in the first column, the exact depths for the annular back fill (i.e. gravel pack, sanitary seal and cuttings) can be determined by use of the drawings on the drilling log.

To resume: filling in the drilling logs is a 4 step process:

Describe the samples and depth
Indicate permeable and impermeable layers
Mark the casing, screen and sump in the column “PVC pipe”
Mark the back filling and sanitary seal(s) in the column “back fill”

Groundwater level

When a borehole is drilled ‘dry’, meaning without the use of drilling fluid or With a fluid-drilled where borehole is kept full of water to maintain water pressure, the depth of the water table can easily be determined during drilling. The soil that comes out during drilling will be wet when the groundwater level is reached.

DETERMINE THE DEPTH OF THE WELL SCREEN AND BACK FILLING

Once the soil descriptions are hatched on the drilling log, the visible information can be used to determine the exact depth of the well-screen and annular back fill.

Well-screen, position and length

The well-screen usually does not exceed a length of 6 meter, for manually drilled boreholes. Fine materials are often present in the extreme upper and lower parts of an aquifer. Also thin clay layers might exist in the aquifer. To prevent the fines (which may cause turbidity and pump damage) from entering the well-screen it is important NOT to install the well screen at the same level as these fines in the aquifer. In other words; be sure that the whole screen length is installed in a permeable layer, consisting of sand or gravel! To achieve this in some cases the screen length might be less than 6 meters (but should generally never be less than 3 meter. Although carefully taken, the exact depth of origin of the soil samples might not always be accurate. To avoid fines from entering, it is wise to install the well screen and back fill with a safety margin of at least 1 meter.

Sump

After the installation and during the use of a well, some soil particles may still enter the well-screen. The bigger particles (which can cause damage to the pump) settle down to the bottom of the well by gravity. To prevent loss of well-screen surface area, a sump of 1-2 meter in length, with a closed bottom end is attached to the well-screen.

Thickness of the gravel pack

Once the well-screen position is recorded (hatched) on the drilling log, the position and thickness of the gravel pack can be determined. The annulus (open space) around the well-screen is filled with coarse sand or fine gravel of specific size (gravel pack), up to about 1-2 meter above the top of the well-screen. The extra meters are necessary because during the development of the well, the gravel pack will settle (and shrink). It is therefore good practice to include at least 1-2 meter safety margin above the well-screen during installation of the gravel pack.

Thickness of the sanitary seal

When an impermeable layer is drilled through, it is advised to seal (close) again that whole impermeable layer with clay (bentonite) or cement. To be sure the layer is sealed properly, the thickness of this seal should be at least 3-5 meter. If no impermeable layer was found, and the well is thus placed in the first aquifer, the sanitary seal should be installed directly on top of the gravel pack (1-2 meter above the well-screen) and should have a thickness of at least 5 meter.

Cuttings

On top of the sanitary seal, backfilling of the drilling hole is done by using the cuttings (soil which was drilled up during the drilling process).

Sanitary top-seal

Also a sanitary top-seal of 3-5m thickness should be placed from 3-5m below ground to the surface. it is essential to install a sanitary seal if the well needs to yield good quality water. The sanitary seal can consist of cement or bentonite pellets (the volume of the bentonite pellets will increase many times when it gets wet, and so it seals the hole by expanding). Also natural swelling clays can be used, but they are more difficult to handle than processed bentonite. In many countries bentonite pellets are expensive. In these cases it is recommended to use a cement-water mixture (cement grout). The water and cement are mixed until a thick slurry is created (26 liters of water to one 50 kg bag of cement will make about 33 liters of cement grout). If cement grout is used as a sanitary seal, first a half meter of clay should be back filled on top of the gravel pack to prevent the grout from penetrating the gravel pack.

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Soil Classification for Engineering purposes

November 12, 2020 / GEDLblogger / 0 Comments

Soil classification is the arrangement of different soils with similar properties into groups and subgroups based on their application.

Soils may be classified in a general way as:

Cohesive vs. cohesionless
Fine- grained vs. coarse grained
Residual vs. Transported

However these terms are too general and cover too wide range of physical and engineering properties.

A more refined classification is necessary to determine the suitability of a soil for specific engineering purposes.

Therefore, these terms are collected into SOIL CLASSIFICATION SYSTEMS, usually with some specific engineering purpose in mind.

Most of the soil classification systems that have been developed for engineering purposes are based on simple index properties such as particle-size distribution and plasticity.

NEED FOR SOIL CLASSIFICATION SYSTEMS

A soil classification system represents, in effect, a language of communication between engineers.
It enables one to use the engineering experience of others.
The engineering properties have been found to correlate quite well with the index and classification properties of a given soil deposit.
Therefore, by knowing the soil classification, the engineer already has a fairly good general idea of the way the soil will behave.

Why more than one Classification System are in use?

Classification systems are used to group soils in accordance with their general behavior under given physical conditions.
Soils that are grouped in order of performance for ONE SET of Physical CONDITIONS will not necessarily have the same order for performance under other set of physical conditions.
This led to classifying soil by use, and each agency (Like FAA, AASHTO, USBR) has in mind specific use for the soils.

SOIL CLASSIFICATION SYSTEMS

The two major systems used at present are AASHTO and USCS. Both systems take into account the particle-size distribution and plasticity.

The AASHTO classification system is used mostly by highway departments. Geotechnical engineers generally prefer the Unified system USCS

A. AASHTO CLASSIFICATION SYSTEM

The AASHTO soil classification system was originally developed in the late 1920’s (1929) by the U.S. Bureau of Public Roads (BPR) for the classification of soils for highway subgrade use.
It was developed as a result of the work of Hogentogler in the 1920’s.
Adopted by Bureau of Public Roads in 1931.
AASHTO : Acronym of American Association of State Highway and Transportation Officials.
Originally, the system classified soil as being either a group A or a Group B.
A Group A soil was able to maintain uniform pavement support at all location whereas the Group B soils were not.
The B designation was subsequently deleted, leaving only A soils in the classification system.
Consequently, the “A” still remains in an AASHTO classification of a soil type, but it no longer has any real significance.
The A soils were subdivided into eight subgrade soil groups. A-1 through A-8.
It went through various revisions since 1929, and the classification system received its last revision in 1974.
ASTM D-3282; AASHTO method M145

REMARKS

According to this system, soil is classified into eight major groups, A-1 through A-8.
Soil group A-8 is peat (very organic) or muck (thin very watery, and with considerable organic material).
A soil is classified according to the table by proceeding from left to right, top to bottom, column by column on the table to find the first group in which the soil test data will fit.
The first group from the left into which the test data will fit is the correct classification.
The classification process stops at this point regardless if another column farther to the right can also qualify.

B. UNIFIED SOIL CLASSIFICATION SYSTEM (USCS)

This system was developed by Arthur Casagrande in 1942 for use in the air field construction works undertaken by the Army Corps of Engineers during WW II.
To make it applicable to DAMS and other constructions besides airfields, it was revised in 1952 in cooperation with the USBR.
The system was last revised in 1984 by the ASTM by the addition of a GROUP NAME to the group symbol. This modification has not been adopted by some agencies which use USCS to classify soils.
ASTM Test Designation D-2487.

This system is the most popular soil classification system among geotechnical engineers.

This system classifies soils under three broad categories:

Coarse-grained soils < =50% passes sieve No. 200
Fine-grained soils > 50% passes sieve No. 200
Organic

Criteria for USCS:

Grain size
Cu, Cc
Plasticity (Plasticity chart)

Tests required

Grain-size analysis
Liquid Limit
Plastic Limit

Comparison of the USCS and AASHTO Classification Systems

In AASHTO if 35% passes No. 200 fined-grainedèIn USCS if 50% passes No. 200 fined grained
In AASHTO Sieve No. 10 is used to separate gravel from sand, in USCS it is Sieve No.4.
In USCS, the gravely and sandy soils are clearly separated, in the AASHTO system they are not.
The symbols GW, SM, CH and others that are used in the USCS are more descriptive of the soil properties than the A symbols used in the AASHTO system.
The classification of organic soils such as OL, OH, and Pt has been provided in the USCS. In AASHTO system, there is no place for organic soils. (A-8 has been taken out).
In AASHTO PI is used to distinguish between silt and clay (LL appears only in distinguishing A-7-5 and A-7-6). In USCS both PI and LL (plasticity chart) are used.
USCS distinguishes high and low plastic fine-grained soils.
Both AASHTO and USCS are better than most other available systems when applied to engineering or construction applications.
Both AASHTO and USCS systems have the advantage of having been used for many years and having gained acceptance in the engineering and construction fields.

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Pore-pressure prediction

Pore pressure prediction from seismic data analysis before drilling

Pore pressure prediction from wireline logs and logging while drillings logs

Pressure prediction and evaluation from drilling and mud-logging data

After the wellbore – Near Wellbore Stress-State

Hoop Stress σø

Axial Stress σz

Radial Stress σr

Wellbore stability controllable parameters:

Effect of Mud Weight/ECD

Mud Filter Cake and Permeable Formations

Hole Inclination and Direction

Bottom-hole Temperature

Time-dependent effects.

Providing a stable wellbore

Mechanical Stability

Warning Signs of Mechanical Stability Problems

Wellbore stability analysis

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Wellsite geologist

What are the functions of wellsite geologist?

Drill cuttings analysis and description

Data correlations and decisions

Formation evaluation services team supervision

Coring operations

Casing point determination

Geosteering and Horizontal drilling

Reporting

Safety and communication

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Normal compaction trend line (NCTL) Methods

Estimating Overburden Gradient

Plotting the overburden gradient versus depth gives a curve

Requirements for formation pressure/fracture gradient FP/Frac Calculations

Estimating formation pressure Pf

Equivalent Depth Method

Ratios Method

Eaton Method

Shale Resistivity:

Sonic:

Formation tests

Estimating Formation Pressure from Kick

Calculating Fracture Gradient

Poisson’s Ratio

Calculating Frac: Eaton Method

Calculating Frac: Daines Method

Indicators from Wellbore Instability

Shear failures

Tensile failure

Procedures of Real-Time Pore Pressure Detection

The real-time monitoring should ensure that:

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Qualitative Pressure detection

Drilling Rate – Rate of Penetration (ROP)

Factors Affecting ROP

Effects of Overbalance:

‘d’ Exponent

‘d’ Exponent vs. Compaction Trend

Corrected ‘d’ Exponent (dcs)

Dcs Bit Wear Correction

Calculating formation pressure from Dcs

Setting ‘d’ Exponent Trend

Other drilling parameters for real time pore pressure detection

MUD LOGGING LAGGED METHODS OF REAL-TIME PORE PRESSURE DETECTION

Mechanism generating cavings under overpressure conditions

Shale density

Mud losses

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What is a Kick

Warning signs of a kick

Flow rate increase

Pit volume increase

Flowing well with pumps off

Pump pressure decrease and pump stroke increase

Improper hole fill-up on trips

String weight change

Drilling break

Cut mud weight

Primary well control

Secondary well control

Hoop Stress σ_ø

∂_f = Formation fluid density (no unit)

∂_m = Matrix density (no unit)

Pf = Hd /10 instead of h d / 10