This section will be a brief introduction into the methods used to evaluate the well bore environment, the formations drilled and the formations beyond the wellbore.
Typically this is done to better the operators’ knowledge base and understanding of the formations it encounters, build a better model of the drilling environment which in turn helps make drilling easier and possibly cheaper. For example if you knew the location of a troublesome zone you could modify your wellbore trajectory beforehand or take proper precautions to avoid unnecessary rig time.
The most important reason for logging is to further your understanding of the reservoir, to better know your “pay dirt”. The more you know the better you can produce from it, the better you can produce from it the more efficiently you can do so and thus minimize cost while at the same time maximizing the revenue. It can also help with long term planning of the production profile of the reservoir thus helping to extend the life of the reservoir and in so doing keep the revenue stream derived from the production of hydrocarbons going for a much longer time. This will ensure long term value for money from the reservoir, recouping of investments and a greater possibility of higher profits.
- Mud Logging – done onsite by the analysis of drilled cuttings, most times done under the supervision of the wellsite geologist, or the cuttings are taken at regular intervals and sent to a lab for testing.
- MWD – Measurement While Drilling – usually involves a logging assemble that is part of the drill string being rotated in the hole. It provides logging data while drilling usually at a distance behind the bit.
- Wireline Logging – logging tools suspended by wireline that are lowered into the hole after drilling of the wellbore is completed but before casing is run. These are generally considered the benchmark of formation evaluation despite advancements in MWD technology.
- Drill Stem Testing
- Pressure Transient Analysis
The logging of a well bore is the process of measuring the electrical resistivity of the surrounding formation and the fluids within. It is known that the electrical resistivity of rock is high however the resistivity of minerals and fluids that occupy the pore spaces of said rock have proven to be low in comparison to the rock. This has lead to the ability to measure the resistivities and make a determination as to the formation, its characteristics and the type of formation fluids it may contain.
There are several mechanisms by which we evaluate the wellbore. However each mechanisms is set up to make a measurement and help to make a determination on a specific petrophysical property, be it porosity, permeability, hydrocarbon saturation, formation thickness and area.
This is the pore volume per unit volume of formation, it is the total volume of a sample that is occupied by voids. Typically this parameter can be obtained from measurements made by sonic, density or a neutron log.
The fraction of the pore volume that contains a fluid.
This is a measure of well the fluids an move through the formation.
It refers to the shape, dimension and orientation of the reservoir.
This type of log measures a substance’s ability to impede the flow of an electric current.
It is primarily used to determine the saturation of non-invaded virgin formation. Using resistivity deep and shallow resistivity can be used to determine the producibility. It is primarily used to differentiate between water bearing and hydrocarbon sands.
Oil and gas are electrical insulators the presence of water depending on the salinity will conduct electricity. When compared oil and gas the resistivity of which is infinitely high.
Rock is an insulator as such
Porous rock is also an insulator as such
Porous rock with water the resistivity decreases.
Include more water the resistivity further decreases.
Add hydrocarbons then they displace the water and the resistivities increase.
Water saturation (Sw) is calculated from porosity and resistivity.
Two assumptions are made:
- If porosity is measured 3 inches from the borehole then you must assume it to be representative of the entire formation.
- Deep resistivity 5-7ft. from the borehole should represent the uninvaded zone.
Essentially it emits a sound pulse and has a receiver that picks up the sound pulse as it passes the receiver. This produces a transit time and generates a wave form that can be interpreted. In the sonic log the velocity of the wave form through the rock matrix will help to determine the porosity as it is known that porosity decreases the sound velocity.
If shale exist within the porosity values are increased by an amount proportional to the bulk volume fraction of shale.
These logs use a radioactive source that emits gamma rays that are essentially high velocity particles that interact with the formation. The result is that the gamma rays lose energy upon collision with the formation, this lowered energy is detected and a determination can be made as to the formation density.
Specifically the tool detects the electron density reaching the detector, which in turn is determined by the electron density of the formation which is related to the true bulk density of the formation.
They are used to specifically detect four main characteristics:
- Mineral identification
- Gas detection
- Hydrocarbon density
Used for the delineation of porous formations and porosity determination by responding to the amount of hydrogen in the formation. The log can measure the liquid filled porosity, and is combined with density logs for porosity and lithology determination.
A high neutron account indicates a low porosity, while low indicates high porosity. When a gas is measured the porosity will appear very low.
- Resolution decreases in boreholes greater than 10ins.
- Mud density and type can either induces increased count rates or cause scattering.
- Tool eccentricity can affect the count rate
- Mud cake can affect the porosity results especially if is thick. Porosity results may be too high.
This is a record of the direct current voltage differences between the naturally occurring potential maintained by a movable electrode in the borehole and a fixed potential located at the surface. The potential is as a result in the difference between the salinity of the drilling and formation fluid.
The SP log can be used to identify:
- Permeable formations
- Boundaries of permanent formations
- Porosity determinations
- The resistivity of formation water
The readings opposite shales are consistent and are referred to as a “shale baseline”. Opposite permeable formations the SP will move to the left or to the right. The formation boundaries are usually indicated by an inflection point. The log will lose resolution in highly resistive beds, or those with little or no permeability. It is NOT to be run in drilling fluid that is salt or oil based, or air.
- Spurious spikes caused by external electrical signals.
- Abnormality caused by highly resistive formations.
- Noisy signal cause by improper grounding.
- Gamma Ray (GR)
188.8.131.52. Rw from SP
- Determine formation temperature
- Find Rmf and Tf
- Convert Rmf at Tf to a Rmfe value
- Compute the Rmfe/Rwe ration from the SP
- Compute Rwe
- Convert Rwe at formation temperature to a Rw value
Measures the natural resistivity of the formations in the borehole. Good for the identifying lithology and correlation purposes. The GR log usually reflects the shale content of the formations because of the concentrations of radioactive materials in the shales/clay. Shale free sandstones and carbonates have low gamma ray values unless contaminants are present.
They are used to calculate the shale volumes and in environments where the SP log can’t be run.
Typically used for:
- Identifying lithologies
- Depth control
- Shale content determination
- Can be run in many different borehole environments
The GR tool must be done at relatively low speeds to give good bed definitions typically 1800 – 3600ft/hr.
184.108.40.206. Gamma Ray Curve
The vertical resolution would depend on the logging speed and thee constant used. The higher the tool intensity the greater the detection efficiency the greater the vertical efficiency. Practical logging speeds about 50ft./hr. can detect one foot thick beds.
220.127.116.11. Short Normal
The usefulness of the curve will be determined by the vertical resolution. The short normal (SN) is useful as long as the contrasts between the drilling fluid and formation resistivities are not too great. Resistivity beds will appear thinner by the arm spacing (16ins.), and conductive beds appear thicker by the same amount. It is NOT run in highly resistive formations, because the curve can become distorted. It measures the resistivity of the invaded zone (Ri) and works best in conductive high resistive muds.
Inflection points give formation boundaries.
18.104.22.168. Laterolog curves
The best for locating formation boundaries. The range of their application extends to very high resistive formations and there are no depth shifts or reversals. Curve resolution is usually about 2.0ft. This tool measures apparent resistivity (Ra) and must be corrected for Rt.
22.214.171.124. Induction Log
Induction log curves loose resolution in beds that are less than 4ft. The presence of BOTH resistivity and conductivity curves provide log readings with god contrast ranging from low resistivities up to 200.0Ω-m.
They are most effective in medium to high porosity formations and can be used in any borehole fluid. They are used for Rt determination, these values are best when Rxo is greater than Rt.
- High conductivity zones can affect the log
- Log response affected by:
- Filtrate invasion
- Hydrocarbon mobility
- Filtrate to formation water ratio
- Coil spacing of the tool
- Borehole response based on mud conductivity
These logs are capable of detecting formations less than 1.0in. thick, if the mud cake is very thin.
Micro-laterologs can be used in salt muds and high resistivities. Their response will be affected by mud cake greater than thick.
Typically used to measure Rxo and determine permeable beds by detecting mudcake.
- Shallow invasion in porous and permeable formations can affect resistivity.
- Very thick mudcake decreases the effectiveness of the tool
- High Rxo vales in comparison to Rmf can result in poor logs
- If pads are not in contact with formation logs can be of poor quality
- Shaly sands will lead to lowered measured resistivities. This may lead to higher than normal porosities.
This uses a combination of gamma ray and neutron density logs. Usually the gamma ray mimics the density log and the neutron is the reverse/mirror image of the density log. A shale point could be interpreted as a point where the neutron and density plots diverge. This would correlate to a spike in the gamma log or elevated section.
|Log Type||Log Name||Curve Characteristics||Interpretation|
|Lithology Logs||Gamma Ray & Spontaneous Potential (SP)||Deflection to the right||Shale|
|Deflection to the left||Sand|
|Resistivity Logs||Deep Resistivity||High||Hydrocarbons|
|Tight Streaks||Low porosity|
|Separation between the resistivities||Formation and drilling fluids are different|
|Formation is permeable|
|Porosity Logs||Density||Measures the bulk/average density of the formation|
|Neutron||Deflection to the left||More Porous|
|Deflection to the right||Less Porous|
|Neutron readings to the left of density||Shale|
|Neutron readings to the right of density||Gas sand|
|Neutron & density readings overlap||Wet OR Oil Sand|
Gamma Ray & SP
- Curve Characteristics
- Left Deflection – Sand
- Right Deflection – Shale
- Curve Characteristics
- High – Hydrocarbons
- Tight – Streaks Low Porosity
- Low – Shale or Wet Sand
- Curve Characteristics
- Bulk Measurement value of density
- Curve Characteristics
- Deflection to Left – More Porous
- Deflection to Right – Less Porous
- Neutron to the Left of Density – Shale
- Neutron to the right of Density – Gas Sand
- Neutron and Density Overlap – Wet OR Oil Sand
- Well Deliverability
- Characterise formation damage
- Identify produced fluids
- Determine the volume ratios of fluids
- Obtain fluid samples
- Evaluate completion efficiency
- Evaluate possible treatments
- Can be used to asses
- Reservoir extents and geometry
- Hydraulic communication between wells
- Reservoir heterogeneities
- Reservoir parameters
- Draw Down
- Fall-Off Test
- Interference Test
- Two rate flow Test
Fluid flow in a porous medium is governed by the diffusivity equation, assumptions are made to bring it to its simplest form:
- The reservoir is homogenous
- Fluid flow is horizontal only
- Fluid is only of one phase and slightly compressible
- Darcy’s Law applies
- Pressure gradients are small
From the diffusivity equation we can see that the important factors are the change in pressure with respect to the change in time.
Before sand face pressure readings can be made some time must be allowed for wellbore unloading. This occurs when fluid within the wellbore prevents the surface flow rate from following the sand face flow rate. The principle applies to both drawdown and build-up tests.
This is the damaged formation located at the edge of the wellbore which affects the permeability. This change is usually due to the drilling and completions activities that were performed on the well bore and are reversible.
The skin value is dimensionless and independent of flow rate, however the pressure drop is flow rate dependant and the subsequent skin can affect the productivity index (PI) of the well. Typically acidizing helps improve said productivity.
However it must be said that if the perforations are good meaning that if you achieve good penetration then even if there is skin its effect may not be felt i.e. the pressure drop is not as less than ideal.
When calculating a good skin factor is less than zero, a bad one greater than zero and indicates the need for stimulation.
Helps to estimate:
- Reservoir properties
- Identify the reservoir model
- Identify the flow patterns during the test
Composed of three regions: Early Times, Middle Times & Late Times.
- Early Time :
- Pressure transient being in the damaged or stimulated zone
- Unloading or After flow of stored wellbore fluids
- Middle Time :
- Pressure transient in undamaged zone of formation
- Late Time :
- Encountering reservoir boundaries
- Interference effects from other producing wells
- Massive change in reservoir properties
- As the name suggests refers to the distortion of data due to storage of fluids in the wellbore.
- Effect on Flow Test
- Known as wellbore unloading where initial production is due to fluid stored in the wellbore.
- These fluids must be produced before surface flow rate equals bottom hole flow rate.
- Assumption of constant bottom hole flow rate does not hold during unloading.
- Effect on Pressure Buildup Test
- Known as after flow whereby fluids continue to flow into the wellbore once shut-in.
- This compresses the wellbore fluids and stores more fluid
4.7. Damage and Stimulation Analysis
- Wellbores may have zones of reduced permeability caused by drilling or completions operations.
- This is known as the skin effect which is modeled as an infinitesimally small zone with reduced permeability.
- This zone may also be stimulated by acidization or hydraulic fracturing.
- A positive skin factor represents a damaged zone with reduced permeability.
- A negative skin factor represents a stimulated zone with increased permeability.
Bassiouni, Zaki. 1994. Theory, Measurement and Interpretation of Well Logs. Richardson Texas: Society of Petroleum Engineers.