Guidelines and Program for Laboratory Formation Damage Testing
- 1 Recommended Practice for Laboratory Formation Damage Tests
- 1.1 Core Preparation and Characterization
- 1.2 Fluid Preparation
- 2 References
Recommended Practice for Laboratory Formation Damage Tests
The following procedure has been designed to provide a methodology for assessing formation damage in a variety of testing situations. Consequently, it is not rigorous in all areas and operator selection of the precise method or technique used is necessary at several points in the procedure. This procedure will however serve to minimize variability in test results if it is accurately followed and, if departures from this procedure are documented, it will help in the comparison of data derived from different tests. This procedure is not meant to provide detailed instructions on the use of the various pieces of equipment referred to. It is assumed that the reader will have a good working knowledge of the principles and practices involved in formation damage testing. When reporting results obtained using this procedure, details of all departures from these recommendations should be recorded in the final report along with details of methods used where more than one option is provided.
Core Preparation and Characterization
Cutting and Trimming the Plugs.
Plugs should be cut to give a minimum diameter of 1 inch (2.54 cm). Larger plugs, sized to fit particular core holders are preferable. The samples should have a minimum length of 1 inch (2.54 cm) and should be taken from the center of the core to minimize the impact of any coring fluid invasion. The plugging method and drill bit lubricant used during plugging will be determined by the state of preservation of the sample and the reservoir type. Cutting Consolidated Core. A standard core analysis rotary core plugger should be used with lubricant selected as below:
a. Well preserved core. If the core is well preserved then the appropriate fluid for the zone from which it is derived should be used; i.e. formation brine or crude oil for an oil well and formation brine for a gas well (using gas as a lubricant may cause precipitation from formation brine inside the core).
b. Poorly preserved core. If the core is poorly preserved and will require cleaning prior to testing, then the plugging fluid should be inert mineral oil—fluids such as crude oil or formation brine should not be used in this case as they may cause precipitation within the core.
Cutting Unconsolidated Core. One of the following two methods should be used depending on the state of the sample:
a. Homogeneous sample. Plunge plugging, where a sharp-edged metallic cylinder is pushed into the soft rock, should be used.
b. Inhomogeneous sample. If the sample contains hard nodules, cement patches or lamination then a rotary plugger should be used with either compressed air (sample at ambient temperature) or liquid nitrogen (frozen sample) as a lubricant.
Trimming the Plugs. After plugging, the samples should be trimmed (lubricant as for plugging) to give flat end faces perpendicular to the plug sides. The samples should be stored under the plugging fluid prior to cleaning or testing. The end faces of all plug samples should be cleaned of fines/rock flour generated during trimming.
Mounting and Labeling the Plugs.
At this stage the samples should be encased in inert material leaving the end faces exposed, using PTFE tape, together with heat shrink tubing. For poorly consolidated samples it may also be necessary to apply restraining grids to the plug end faces. The samples should be assigned a wellbore and a formation end face which are annotated on the side of the plug and not on the end faces.
Cleaning and Drying.
Once a cleaning and drying method has been selected, it should be identical for all samples in a particular study. See notes in the accompanying text for definitions of the terms Native State, Cleaned Sample and Restored State. Native State Cores. Native State samples should not be cleaned and should be prepared to Swi (irreducible water saturation) with the appropriate single phase fluid using one of the methods described in Section "Preparation to Base Saturation" given below.
Non-Native State Cores. For core samples not in their Native State, cleaning is required. Cleaned samples may be obtained in one of the following ways: a. Samples which do not contain delicate or sensitive minerals can be cleaned in standard core analysis soxhlets using solvents or solvent mixtures and dried in a high temperature (90°C) oven.
Samples containing delicate or sensitive minerals such as illite or smectite should be cleaned by continuous immersion in cold static solvents and dried by critical point drying. If the equipment required is not available or if a faster technique is required the samples can be cleaned using continuous immersion soxhlets and dried in a low temperature (60°C) oven. Cleaned and dried samples should be stored in a desiccator prior to measurement of base parameters.
Note: Commonly used solvents for cleaning include toluene, xylene, methanol, chloroform and acetone. There is no general agreement over which solvent is best in a given situation.
b. Samples can be cleaned in core holders by flowing miscible solvents (or solvent mixtures).
c. Samples can be "cleaned" by flowing alternatively light mineral oil (or crude oil if sufficient quantities are available) and formation brine until complete displacement of original fluids is achieved. The cleaning is ended by flowing oil to Swi and if necessary replacing the mineral oil with crude oil by miscible flooding at Swi. Reservoir temperature should be used.
Restored State Samples. If a Restored State sample is required, this can be achieved by first of all following the procedures outlined in Section "Non-Native State Cores" above, saturating the sample as described in Section "Plug Saturation" given below, and then aging at reservoir conditions for an extended period of time (3-6 weeks).
Selection of Duplicates. Prior to the flood tests, a sufficient number of duplicate plugs should be selected so that the entire test program can be conducted using essentially the same sample of rock. The following criteria are to be used during plug selection:
a. Similar permeability (preferably within 20% as determined by Ka (or K0 for native state samples) measurement
b. Similar grain size/pore throat size distribution (determined by SEM, thin section and possibly mercury injection of plug trims or carcass material)
c. Similar composition/lithology (determined by XRD, SEM, thin sections of trims/carcass or CT scans of plugs)
It is difficult to quantity the parameters in b) and c) and the comparative suitability of duplicates must be made using expert judgement.
100% saturation is defined as being within 2% of base saturation. Saturation With Formation Brine. Cleaned samples should initially be saturated with formation brine. This may be achieved using one of the following methods as determined by the cleaning process previously employed:
a. If the samples have been cleaned using immersion methods then the dry samples are placed in a saturating vessel A vacuum is applied and then formation brine is introduced and sufficient pressure is applied to ensure 100% formation brine saturation (as determined by weighing).
b. If the samples have been cleaned by flowing solvents in a core holder ending with 100% methanol saturation (as determined by effluent composition) then the methanol can be exchanged by miscible flooding with formation brine to 100% water saturation (as determined by effluent composition). Gas phase should be eliminated by applying back pressure.
Preparation to Base Saturation. Prior to the flood test, for both Native State and Restored State, the samples should be prepared to a defined saturation/capillary pressure. For both oil and gas wells, irreducible formation brine saturation should be used. There are various methods which can be used to achieve this saturation. These include porous plate, dynamic core holder and ultracentrifuge. Due to the wide variety of core sample characteristics and test objectives, no one method can be recommended as being the most applicable for all situations. After preparation to base saturation, samples should be stored under the appropriate fluid and conditions prior to return permeability testing.
Simulated Formation Water.
Simulated formation water (SFW) should be prepared using analytical grade inorganic salts to obtain the appropriate levels of the ions, as determined by elemental analysis, and then degassed. The SFW should be filtered to 0.45 micron.
Fluids Used for Initial and Final Permeabilities—
Kerosene or Inert Mineral Oil. Kerosene or inert mineral oil should be filtered to 0.45 micron. Formation Brine. Formation brine, if available, should be filtered to 0.45 micron at reservoir temperature. Alternatively, simulated formation water (SFW) should be freshly prepared as discussed in Section "Simulated Formation Water," given above. Crude Oil. It is usual to use dead crude but since it may contain a certain amount of produced water, this should be removed. The crude oil should be filtered using a 0.45 micron filter at a temperature above the wax appearance temperature. Gases. Oxygen-free nitrogen, filtered through a 0.45 micron filter, should be used. After filtration, the nitrogen should be humidified at inlet pressure conditions to prevent the sample from drying out during testing.
Drilling Fluid (Whole Mud). Drilling fluids to be used in return permeability testing should be as representative as possible. In the case of laboratory prepared muds, they should contain all the components of the proposed formulation including weighting agents and contaminants and should be mixed according to standard API procedures where available.
Laboratory muds should be artificially aged by hot rolling for 16 hours at the relevant bottom hole temperature, prior to testing. These should also be passed through a mesh sieve to simulate mud conditioning where relevant (mesh size to reflect shale shaker screen sizes used in the field).
In the case of field muds, the mud should be sheared on a Silverson mixer with the appropriate head (square hole emulsor screen for invert muds, 0-polymer head for water-based muds) for 5 minutes per laboratory barrel (350 ml) prior to use to ensure that the mud is in a representative state. Again, the mud should be passed through a mesh sieve to simulate mud conditioning where relevant.
Drilling Fluid (Filtrate). Drilling fluid should be prepared as above, then filtered such that the filtrate obtained is representative of the filtrate lost to the formation through the filter cake.
Filtrate should be obtained either by centrifuging the sample or by using a High Temperature High Pressure fluid loss cell. The filtrate collected is then further filtered to approximately one third of the average pore throat diameter of the reservoir core and should be used within 16 hours of filtering.
Solids Free Completion Fluid. Solids free completion fluids (e.g., brine, acid) should be prepared including all additives planned for the well. They should be filtered to the appropriate specification for that formation and/or field practice.
Completion Fluid Containing Solids. This section refers mainly to Loss Control Material (LCM). These fluids should be prepared such that the particle size distribution is representative of that expected downhole. Filtering of the prepared fluid is optional, depending on the type of effects to be measured.
Wellbore Fluid Placement.
The prepared sample for evaluation should be loaded into a core holder capable of attaining reservoir net confining pressure and temperature ratings for the matching of reservoir in situ conditions. Pressures and flow rates should be continuously logged as functions of time. The core sample should be mounted in the horizontal position for analysis. The confining stress on the sample should be gradually increased while at the same time the pore pressure of the fluid in place is also increased to maintain a net confining stress ratio equivalent to the in situ reservoir stress conditions. The rate of increase of net stress on the sample should not exceed 1000 psi (68 bar) per hour.
The test apparatus and sample should be heated to an equivalent reservoir temperature. During heating, the pore pressure and confining stress should be adjusted to maintain initial conditions. Monitoring of the sample temperature and applied pore and confining pressures during this process is required to determine when reservoir conditions have been attained. The sample should be allowed to stabilize at the test temperature and pressure for at least 4 hours before testing begins.
Note: In order to prevent damage in the sample due to fines mobilization during flow testing it is recommended that a separate critical velocity test be performed to determine the flow rates which can be applied without causing permeability reductions due to fines migration. Preparation of the critical velocity sample should be the same as the preparation technique used for the test samples.
Formation fluid should be flowed in the production direction (from "formation to wellbore") by injection at constant rate. Where the critical velocity is not known, the flow rate should be as low as possible yet sufficient to generate a measurable pressure drop. Where the critical velocity is known for the test material, then the flow rate should be <50% of the critical rate. The differential pressure across the sample should be recorded. Particular regard should be paid to anomalies caused by mobilization of fine material within the test sample. The flow should be maintained until the pressure drop has stabilized and does not vary by more than 5% for a minimum of 10 pore volumes. Fluid flow is ceased once initial permeability is established.
Drilling Fluid Placement—
Whole Mud. To simulate well conditions, drilling fluid should be flowed over the 'wellbore' face of the sample. The drilling fluid should be pre-heated prior to placement to match the bottom hole temperature. The drilling fluid should be applied to the sample face at the same overbalance pressure as in the reservoir and should be dynamically circulated over the face of the test sample for a minimum of 4 hours. Where comparative testing of mud on the formation is required the mud flow rate will be a constant for each mud type. During circulation the drilling fluid pressure and pore pressure should be recorded to ensure the values remain stable (less than 5% variation). During dynamic drilling fluid circulation the amount of fluid invasion into the test sample should be monitored at the "formation" end of the sample.
The method of monitoring should be recorded. Invasion volume as a function of time should be recorded to allow the evaluation of spurt loss as the mud cake builds up and the effectiveness of the cake to prevent filtrate invasion into the test sample (leak off). Static drilling fluid placement should follow the dynamic placement. During the static placement the mud pressure should be maintained without flowing fluid over the "wellbore" face of the sample. The static placement should be for a minimum of 16 hours. As in the dynamic placement, recording of invasion volume as function of time measured at the "formation" face of the sample during the static placement is required to monitor mud cake performance. Following the static placement the mud should be dynamically circulated for a minimum of 1 hour. A fluid system that requires a wash or breaker fluid, will need to have a step included into the test sequence in which placement and contact with this fluid are simulated.
Mud Filtrate. 10 pore volumes of the mud filtrate should be injected at the reservoir temperature through the core in the "wellbore to formation" direction at 1 ml/min and the pressure differential measured.
Completion Fluid Placement—
Solids-Free Completion Fluid. 10 pore volumes of the solids-free completion fluid should be injected through the core in the wellbore to formation direction at the static reservoir temperature. The fluid should be injected at a rate similar to that used when establishing initial permeability (Section "Initial Permeability," given above).
Fluid Loss Control Pill. Fluid loss control pills should be exposed to the wellbore face at the appropriate overbalance. This should be carried out at static reservoir temperature for a representative amount of time as determined by the operation being simulated, but a 16 hour minimum is recommended. Fluid loss over time and differential pressure during the exposure period should be recorded as well as the filter cake thickness.
Any clean-up treatment should be flowed over the wellbore face of the sample at a pressure differential appropriate to the reservoir conditions. Fluid should be allowed to flow through the core once breakthrough is achieved and the pressure differential should be maintained until a representative amount of fluid has been lost. A shut in period either before or after circulating the fluid may be utilized if appropriate to simulate field practice. The amount of fluid lost into the core over time and the differential pressure should be recorded.
After the placement of drilling fluid (and possibly other fluids) it is important to simulate a return to production in the "formation to wellbore" direction. This can be performed under conditions of constant pressure or constant flow rate. The permeability is determined after either of these methods.
a. Determination of flow rate at constant pressure (drawdown). Drawdown should be performed by decreasing the pressure at the wellbore end of the plug and maintaining the formation end pressure at pore pressure allowing flow through the plug, mud cake and mud. The pressure drop should simulate that to be used in the reservoir. Drawdown should be continued until constant flow rate is achieved. If this is not achieved, the fact should be included in the report. Pressure and flow rate should be measured throughout this procedure.
Note: Where permitted by the core holder design, flow regimes incorporating flow across the face of the core should be used.
b. Determination of differential pressure at constant flow rate. This procedure differs from a) above by using a constant flow rate and measuring the corresponding differential pressures across the core. The flow rate should be representative of the flux at the wellbore face. Flow should be continued until constant pressure is achieved. The pressure required for the initiation of flow should be recorded. Determination of Return Permeability. The final or return permeability measurement (or measurements) can be made at two different stages:
a. Immediately after Section "Production Simulation," given above, and when a stable flow rate/pressure drop has been achieved, the permeability of the tested core plug can be measured.
b. After preparation of the core plug in the same way as for the initial permeability (Section "Core Preparation and Characterization," given above), the permeability can be measured.
To determine the return permeability, repeat the procedure used in Section "Initial Permeability," given above, to measure the initial permeability, ensuring that identical fluids and flow rates are used.
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