This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27661, “How Will Subsea Processing and Pumping Technologies Enable Future Deepwater-Field Developments?,” by Phaneendra B. Kondapi, Texas A&M University, and Y. Doreen Chin, Ashesh Srivastava, and Zuying F. Yang, Subsea Engineering Technologies, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
This study examines how subsea processing (SSP) can develop into an important enabling technology for future ultradeepwater-field developments and long-distance tiebacks. The authors identify the gaps that need to be closed and describe the decision-making process during the field-development life cycle by considering the technical and economic constraints of various SSP technologies.
A generalized definition of SSP is any active treatment of the produced fluids at or below the seabed to improve recovery factor of reservoirs. SSP technologies include multiphase pumping, subsea separation, gas compression, and raw-seawater injection.
Subsea separation coupled with liquid boosting is effective in enabling production at very low flowing tubinghead pressures, even in deep water. This method also is well-suited for use where heavy, viscous oil or low reservoir pressure is the rule. Gas fields often are developed with subsea wells and multiphase transport to onshore facilities or to offshore processing platforms. Separation allows decreasing boosting-power requirements. Subsea-separation technology is progressing quickly because of its huge potential in minimizing topside water-handling requirements and separation of gas, oil, and water from the production fluid. Subsea gas-compression technology is one of the faster-growing technologies for large fields requiring pressure boosting (e.g., where subsea-to-beach development solutions result in long tie-back distances). It improves the production and recovery from the reservoir by reducing backpressure on the wells.
As of this writing, more than 25 subsea boosting systems and six major subsea separation systems have been installed or awarded throughout the world. Given the growing number of greenfield and brownfield applications, some analysts anticipate the number of SSP systems installed globally to double by 2020.
The complete paper contains a detailed discussion of the development of these technologies, from their origins to their current incarnations.
SSP is typically considered for systems with a tieback to a host structure and can influence all phases of project life (start-up, plateau production, late life, and tail end). SSP can consist of the following:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27639, “Significant Cost Reduction of Subsea Boosting Systems by Innovative Technologies,” by J. Davalath and D. Wiles, TechnipFMC, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
One of the more promising opportunities for brownfield investment is low-cost subsea boosting systems. These projects do not require the drilling of new wells or significant infrastructure investments in new subsea equipment or new topside facilities. Incremental investments in low-cost boosting systems result in substantial increases in revenues and, therefore, high rates of return. The costs of subsea boosting systems have been reduced by adopting three primary strategies: simplifying the system design to reduce weight and cost, simplifying the installation and intervention, and reducing complexity and risk.
Analyses of well and reservoir conditions suggest that there are hundreds of wells worldwide that have the economic potential for low-cost subsea boosting. The return on investment (ROI) in these cases ranges from 250% to greater than 500%. Subsea boosting systems are a robust and mature technology; worldwide, more than 65 mudline units and more than 50 submersible pumps have been installed. Consequently, 19 operators have addressed production challenges with subsea boosting technology.
Key applications have used subsea pumps as part of a subsea-processing station. For example, subsea pumps were installed to boost liquids separated subsea in three-phase separation systems, for the purposes of debottlenecking topside facilities, in the Petrobras Marlim project and the Statoil Tordis project, the former with horizontal pipe separator technology and the latter with conventional horizontal three-phase separator technology.
Subsea pumps have also been installed downstream of gas/liquid separators in Angola’s Block 17 in the Pazflor Field. This application enabled a higher-pressure boost than could be achieved by multiphase pumps available at that time. The separation of the gas from the liquid enabled the use of a hybrid pump, with centrifugal stages in addition to the helicoaxial stages typical of a multiphase pump, to provide a higher differential pressure.
Improvements in multiphase-pump technology have occurred such that higher differential pressures can be generated as a result of high-speed-motor technology, rapid-control technology, and monitoring systems. Therefore, subsea boosting stations have become less-expensive and more-reliable solutions for increased oil recovery (IOR).
Market PotentialThe need to reduce the backpressure on producing wellheads, and increase the recovery factor from oil and gas reservoirs, is omnipresent in subsea fields. The decision to install subsea boosting on the mudline is made in the context of the incremental improvement in recovery achievable with a subsea pump vs. the recovery achievable by producing the field naturally or by other IOR technologies. Operators have studied key oil-producing regions and have identified many instances in which mudline boosting is the most-viable alternative.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186005, “An Innovative Approach Toward Improving the Relationship Between Flow-Zone Indicators With Lithofacies: A Case Study in a Carbonate Oil Field in the Middle East,” by N.S. Hashim, A.F. Zakaria, and N.A. Ishak, Petronas, prepared for the 2017 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, 8–10 May. The paper has not been peer reviewed.
The F field in the Middle East currently has more than 40 producing wells in the center of the structure. The uneven well distribution limits the understanding of 3D reservoir characterization, particularly in the flank areas. A fit-for-purpose integrated reservoir-characterization study was carried out. The exercise, outlined in the complete paper, confirms the heterogeneity within B formation (the primary oil reservoir within F field), and it captures the changes in reservoir quality laterally and vertically.
F field is located in the northeastern part of the Arabian Peninsula. F field is a low-relief anticlinal structure aligned northwest/southeast, approximately 31 km long and 10 km wide. B formation consists of carbonate-ramp depositional settings, and has an average thickness of 200 m. Multiple development wells were drilled as part of its development plan, and its first oil production was achieved 3 years ago.
Issues with reservoir characterization have arisen because of the uneven well distribution, especially in the flank area. Furthermore, only one conventional core with good recovery was available for Reservoir B, which makes it somewhat difficult to delineate the internal architecture of the carbonate ramp.
B Formation Stratigraphic Interval
B formation subreservoirs include Upper B (UB), Middle B (MB), and Lower B (LB); the MB and LB subreservoirs contain most of the hydrocarbon deposits. UB does not contain any hydrocarbons and is believed to be tight on the basis of log information. Each subreservoir was divided into sub-units (UB-1 and UB-2; MB-1, MB-2, and MB-3; and LB-1, LB-2, and LB-3) on the basis of pressure and fluid information.
One conventional core was taken with a total length of 100 m and total core recovery of 97%. This conventional core covers the Middle B to Lower B subunits. Full-core analysis study was conducted on this conventional core, which includes routine geological analysis, routine core analysis (RCA), special core analysis, and digital rock analysis.
The study identified seven lithofacies.
Bioclastic Mudstone (BM). BM consists of a mostly micrite matrix. It is light gray to pale brown and is moderately bioturbated. In terms of reservoir characteristics, this lithofacies is poor, with no visible porosity. BM is usually deposited in an open marine slope.
Bioclastic Wackestone (BW). As with BM, BW also consists of a micrite matrix. Carbonaceous wispy seams, solution seams, and stylolization are also common in this lithofacies. BW is characterized as tight, with no visible porosity. Its measured porosity ranges from 4 to 21%, with average porosity of only 10% and a permeability range between 0.1 and 7.6 md. BW is likely located in the shallow marine middle ramp.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27747, “Profit Increase With New Subsea Boosting Products,” by Åge Hofstad and Hans Christian Nilsen, Aker Solutions, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
Emphasis on identifying more-efficient subsea boosting solutions has led to a number of initiatives in the industry. A new multiphase-pump technology has been developed that will expand the operation envelope for subsea boosting and create better opportunities for more-effective offshore-field development. A parallel, and equally important, advance has been the development of a new heavy-duty 6-MW subsea motor.
In 2011, a decision was made to abandon twin-screw technology because of the low sand-handling resistance and limited differential-pressure generation with multiphase fluids that these pumps had demonstrated during in-house testing. Thus, a development project was initiated.
For this development project, the main target was to increase pump performance in the following ways:
Reaching these targets would require design of a new motor to operate at higher speeds at twice the power.
It was evident from recent experience that the pump design had to use the rotodynamic principle (dynamic energy transfer to the liquid) and not the positive-displacement principle. Before this multiphase-pump development, a hybrid multiphase pump with both multiphase impellers and radial impellers had shown very good test results when operating with multiphase fluids.
The multiphase impeller design has commonly been a helicoaxial design, which has been the standard until now. However, on the basis of previous experience and tests, a different technology was chosen. This was a mixed-flow impeller in which the flow channel was partly axial and partly radial. This design uses centrifugal action to provide more pressure generation from each impeller. This principle can be termed a helico-mixed-flow design.
From promising initial pilot pump tests, the authors were able to prepare a prediction model for the multiphase pump. The prediction model is, in itself, a challenging piece of work because the fluid conditions will change considerably through the pump. It is necessary to use a stepwise approach and calculate the fluid parameters for each impeller stage.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181526, “New Wireline, In-Situ, Downhole Fluid Compositional Analyses To Enhance Reservoir Characterization and Management,” by Gabor Hursan and S. Mark Ma, Saudi Aramco, and Wael Soleiman, Sami Eyuboglu, Neeraj Sethi, and Nacer Guergueb, Halliburton, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
This study focuses on recent experience in Saudi Arabia with crude-oil compositional analyses during pumpout with a wireline formation tester (WFT). It summarizes experience with the in-situ measurement of methane, ethane, propane, saturates, aromatics, and gas/oil ratio (GOR) on the basis of multivariate optical computing (MOC) conducted at more than 200 pumpout stations in a total of 37 wells drilled with a variety of inclinations, bit sizes, and drilling fluids in several oil and gas fields.
In reservoir-fluid characterization performed in the laboratory conventionally, samples of representative formation fluids are analyzed to determine bulk fluid properties, fluid-phase behavior, and chemical properties. Exploration and evaluation wells are often drilled exclusively for fluid-analysis purposes for which the only way to analyze or capture formation fluids is a downhole pumpout WFT (PWFT). Capturing high-quality reservoir samples is one of the most important objectives in any PWFT job.
The keys to ensure fluid cleanup during pumpout are (1) a set of downhole sensors measuring the pumped fluids and (2) the unambiguous contrast between the drilling-mud filtrate and reservoir fluids as measured by at least one of these sensors. Avoiding such fluid ambiguity is a challenge in many situations. Optical sensors respond with high sensitivity to chemical compositions of fluids. Implemented downhole, these tools can provide a powerful means of differentiating between the oil-based-mud (OBM) filtrate and reservoir oils.
The most valuable benefit of these measurements is the prompt availability of in-situ fluid-composition data without the additional steps of acquiring, transporting, and analyzing physical fluid samples in the laboratory. This process requires durable, robust, and accurate optical sensors that operate reliably and consistently in the hostile downhole environment. One recently developed optical-sensor system is based on an optical device known as an integrated computational element (ICE) that performs the mathematical operation of MOC. For each fluid component, an ICE “core” is engineered such that only one particular fluid component or property is accentuated in the detector response and everything else is muted. This detector response is then used to infer the abundance of the fluid component of interest. These optical elements are typically very broadband and may have a response that extends from 400 to 5000 nm. The high bandwidth of these optical elements combined with their intrinsic high signal/noise ratio enables laboratory-grade optical analysis downhole.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181484, “Experimental and Numerical Investigations on Stress Dependence of Sandstone Electrical Properties and Deviations From Archie’s Law,” by M.F. Farid, J.-Y. Arns, W.V. Pinczewski, and C.H. Arns, University of New South Wales, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
The resistivity index (RI) of Fontainebleau and Bentheimer sandstones was investigated at ambient and reservoir pressures down to low water saturations. The RI measurements show that both sandstones display Archie behavior at elevated pressure. However, at ambient pressure, the RI for Fontainebleau sandstone deviates from Archie behavior at low water saturations. The pore-space images suggest that the deviation from Archie behavior is attributable to the presence of conductive percolating grain-contact regions.
Deviations from Archie’s law are known to occur, particularly at low water saturations, even for clean sandstones. It is unclear whether the deviations from Archie behavior observed at low pressures are also displayed at elevated pressures. In this paper, the authors present laboratory measurements of RI for two strongly water-wet sandstones at ambient and elevated pressures. The measurements are supplemented with high-resolution microcomputed-tomography (CT) imaging in dry and wet states at ambient pressure to determine an accurate description of the open resolved pore space and to attribute a finite porosity to fluid-saturated grain contacts at elevated pressure. Assuming that the main elements responding to effective stress are the grain contacts, grain-contact conductivities are estimated at elevated confining pressures with actual formation-factor measurements for saturated samples at the same confining pressures. These are compared with computations on the micro-CT images. For Bentheimer, which contains image-resolvable clay regions, the clay regions are considered as additional conductive pathways with different stress dependence.
Experimental Procedure. Rock. The Fontainebleau sandstone samples used exhibit relatively low porosity in the range of 4 to 5%, with sample permeabilities of approximately 0.03 to 2.2 md at confining pressures of 500 to 6,000 psi. The Bentheimer sandstone samples used have a porosity of approximately 23.7 to 25.9%, with permeability of the intact samples at approximately 2,000 md over a range of 500 to 6,000 psi in confining pressure.
Fluid. RI and drainage capillary pressure experiments were performed with brine (2% by weight sodium chloride) and air as the wetting and the non-wetting phases, respectively. The density and viscosity of brine were measured to be 1.0166 g/cm3 and 1.0 cp, while 0.00129 g/cm3 and 0.0185 cp were used for the density and viscosity of air, respectively.
Core preparation, as well as image analysis and acquisition, is described in detail in the complete paper. In Fig. 1, the authors illustrate the final phase assignments for Fontainebleau sandstone, including grain/grain boundary labels for a few different saturations and boundary assignments.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185050, “Experimental Study and Modeling of Cryogenic-Fracturing Treatment of Synthetic-Rock Samples With Liquid Nitrogen Under Triaxial Stresses,” by B. Yao and L. Wang, Colorado School of Mines; T. Patterson, Devon Energy; T.J. Kneafsey, Lawrence Berkeley National Laboratory; and X. Yin and Y. Wu, Colorado School of Mines, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.
Cryogenic fracturing is a waterless stimulation technology that uses cryogenic fluids to fracture unconventional oil and gas reservoirs, and, to date, the underlying mechanism has been investigated rarely and is often understood poorly. This study aims to investigate the efficacy and feasibility of cryogenic-fracturing technology in enhancing the permeability of unconventional-reservoir-rock analogs. Laboratory cryogenic-fracturing experiments and finite-difference modeling are integrated to reveal the process and mechanism of cryogenic fluids in creating fractures in synthetic-rock samples.
Traditional hydraulic fracturing relies on mostly water-based fracturing fluids and usually consumes a tremendous amount of water. The usage of water not only can cause potential formation-damage issues but also can place a significant stress on local water resources and the environment. Thus, waterless stimulation technologies, especially cryogenic fracturing, are being developed to solve these issues.
Cryogenic fracturing uses cryogenic fluids such as liquid nitrogen to fracture unconventional oil and gas reservoirs. Fractures will be induced by the dramatic change of temperature when a warm body, such as reservoir rock, is exposed to a frigid fluid, such as liquid nitrogen. Although the feasibility of cryogenic-fracturing technology has been demonstrated by both laboratory experiment and pilot field tests, the mechanism behind it was rarely investigated and is poorly understood. A preliminary test involved a series of experiments investigating patterns of surface fractures and the effect of cryogenic treatment after submerging concrete-rock samples into liquid nitrogen. Computed-tomography scans showed that the fracture penetrated into the center of the block after 30 minutes of submersion. Further cryogenic-fluid-injection tests on concrete and shale samples have demonstrated the efficacy of permeability enhancement around the wellbore by injecting liquid nitrogen at both low and high pressures.
To conduct a cryogenic-fracturing treatment in a manner similar to that seen in field applications, the authors created a testing environment with sample sizes (8×8×8 in.) between the core and the real-reservoir scales. Liquid nitrogen was circulated into cubic samples through 6-in.-deep boreholes drilled from the top of the samples and cased with stainless-steel tubing by epoxy for the top 2 in. The confining stresses were applied on each sample by a triaxial-loading system that has the capability of providing a true triaxial-stress condition with different stresses along three different axes. The liquid nitrogen was drawn from a tank, injected directly into the wellbore, and then vented through the annulus space to the environment. The purpose of liquid-nitrogen circulation is to achieve a better cooling effect on the openhole section of the wellbore. Pressure, temperature, and stress data were collected during the experiment.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18880, “Novel Abrasive Perforating With Acid-Soluble Material and Subsequent Coiled-Tubing Jetting-Assisted Stimulation Provide Outstanding Results in Carbonate Gas Well,” by Adrian Buenrostro, Nahr Abulhamayel, Usman Malik, Mohammad Bu Suwaileh, and Saad Driweesh, Saudi Aramco, and Alejandro Chacon, José Camilo Jimenez Fadul, and José Noguera, Halliburton, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission.
Abrasive perforating with coiled tubing (CT) is a technique that has proved to be a valuable alternative to conventional perforating with electric line. The application is particularly valuable whenever a high rate or fracture-stimulation treatment is to follow because of the significant reduction in tortuosity and pumping friction losses across perforations. This paper discusses a novel approach to abrasive perforating, including the first-ever use of an acid-soluble abrasive material and ending with CT-jetting-assisted nitrified stimulation.
Many carbonate gas wells located in the northern section of the Ghawar reservoir exhibit a low-permeability profile and are characterized by having low reservoir pressure. Fracture gradients in a formation in this area of the field are on the order of 1.12 psi/ft, which is considerably greater than that of more-conventional tight gas formations. One particular well, located on the flank of the reservoir, was designed to be completed with a plug-and-perforate acid-fracturing operation, but issues arose with this option that finally caused the abandonment of the fracturing treatment. To find a solution that would be feasible and economically viable, an innovative perforation and stimulation technique was engineered for this well.
Design of the Perforation Technique and Yard Testing
The team was able to source a newly developed acid-soluble abrasive material that enabled the same quality of perforations to be created without performing a cleanout run because the acid from the stimulation would dissolve the abrasive material, saving at least 2 days of operation.
The abrasive material was sourced, and several yard tests were completed to determine if the material had the same abrasive characteristics as common 20/40- or 100-mesh sand. It was necessary to compare the time required to penetrate the steel and cement with the results obtained using common sand. This benchmarking was key to determining if additional time and fluid resources were necessary to obtain the same penetration.
A yard test was set up with two metallic 55-gal drums cut halfway lengthwise and then welded together. This created a receptacle that allowed the team to place a 6⅝-in. casing section with 100% standoff and then fill the entire annular space with cement. The drum was then set on top of cement blocks, and the abrasive-jetting tool was introduced.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 184703, “Improving Casing Integrity by Induction Brazing of Casing Connections,” by D. Ernens, H. Hariharan, W. van Haaften, H.R. Pasaribu, M. Jabs, and R. McKim, Shell, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, The Netherlands, 14–16 March. The paper has not been peer reviewed.
Brazing technology allows metallurgical joining of dissimilar materials by use of a filler material. In this paper, brazing technology applied to casing connections is presented. The brazing process, or temperature/torque/time (TTT) process, is performed with regular casing connections, a filler material deposited by flame spray, and a flux. Two processes were developed, one for expandable-grade material (VM50) and one for quenched-and-tempered-grade material.
Casing connectors continue to be a potential liability in complex wells that use premium connections or expandable liners. The technology presented in this paper applies brazing to casing connectors to improve leak tightness of American Petroleum Institute or premium connectors, ensure leak tightness after severe plastic deformation, and increase torque capacity.
The casing connector needed to have mechanical and pressure integrity before and particularly after expansion. However, the extreme plastic deformation reduced the critical cross section and the effectiveness of the metal-to-metal sealing mechanisms. This proved to be difficult to solve with only mechanical design considerations.
The bond needed relatively high shear strength and enough ductility to cope with the plastic deformation. Furthermore, the bond needed to be made quickly, should not alter the material properties of the expandable material, and should be compatible with standard rig operations. Multiple technologies were investigated to overcome these difficulties, including welding and gluing. However, among the technologies evaluated, only brazing provided the strength and ductility with the relatively high speed for making the joints approaching that of the standard casing running process.
Brazing Process. The brazing process is shown schematically in Fig. 1. The first step involves deposition of the filler material on the threads. This operation is carried out off line, away from the critical path of casing-running operations on the rig. This is followed by a process to make the final brazed joint. Briefly, the pin of the joint is stabbed and made up to a fraction of the required optimal torque; the filler material already deposited on the threads is melted using heat; and the joint is torqued up to its final makeup torque. This is followed by cooling of the joint before running in hole. It is important to note that virtually any casing connector can be joined with this technology.
Filler-Material Selection on the Basis of Pipe Grade. The type of filler material is determined on the basis of the pipe grade, which, in turn, is determined by the application. To determine the sensitivity of the pipe grade to the effect of heat treatment, a set of simple experiments was carried out.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181414, “Monitoring of Matrix Acidizing by Use of Resistivity Measurements,” by Mehdi Ghommem, American University of Sharjah, and Xiangdong Qiu, Dominic Brady, Firas Al-Tajar, Steve Crary, and Alaa Mahjoub, Schlumberger, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
This paper describes the testing of a novel concept based on resistivity measurements to monitor acid-stimulation operations. It is believed that the proposed concept for monitoring the wormholing process can be adopted in the field with the deployment of induction tools. The outcome of this novel monitoring concept is expected to provide an unprecedented level of understanding of the depth, number, and type of wormholes being created downhole.
Induction-logging tools can be viewed as an attractive option for characterizing wormhole morphology resulting from the acidizing process and can be used to assess acid-stimulation operations. The authors propose to extend the use of resistivity-logging tools for evaluating acid-stimulation jobs after well cleanup. This concept relies on the significant variations in the electrical resistivity of the different fluids and chemicals involved in the acidizing process and the increase in the effective porosity in the near-wellbore region resulting from the acid reactive dissolution. In this work, the authors conducted resistivity measurements while acidizing carbonate core samples. To do so, an electrically sensitive coreflooding setup was designed to conduct acidizing tests of carbonate core samples while measuring the change in the electrical resistivity at multiple points along the core and in real time. The paper shows the potential use of such measurements to monitor wormhole penetration and branching in real time. A yard test was conducted to verify the response of a real induction tool to simulated wormholing features.
Resistivity Measurements While Coreflooding
Experimental Setup and Procedure. A three-phase methodology was followed: rock-sample characterization, coreflooding and resistivity measurements, and characterization of the core samples after acidizing to inspect the wormhole structure and invert through the model to close the experimental loop.
Saturation of Cores and Porosity Measurement. The core samples were put under a vacuum for a few hours and weighed. Then, they were saturated with 50,000 ppm of sodium chloride (NaCl) at a pressure of 2,000 psi for a few hours. After saturation, the samples were weighed again; the difference in the weight of dry and saturated samples was simply converted to the pore volume of the rock.
Permeability Measurement. The permeability of the rock samples was measured by the constant-flow-rate method. This was performed by flowing deionized water across the cores in the coreflooding system while recording the pressure drop. The permeability was computed from the pressure drop and corresponding flow rate using Darcy’s law.