Wettability of reservoir rocks is important in understanding the rock properties influencing the fluid displacement in porous media. The magnitude of wettability is provided by contact angle, Ammot, and/or USBM methods. This however indicates the average wettability of the examined core samples, and does not give the micro wettability of core samples. We investigated wettability changes by the adsorption and desorption of oil on core particles after ageing process by making measurements of composition analysis of crude oil and core samples, and zeta potential at various conditions before and after ageing process. Carbonated core samples, which were collected from the outcrops in Japan, were used for this study because the restoration of wettability is crucial to understand the rock properties under the natural reservoir conditions. Experimental results showed that the core particles were partially coated with crude oil although the zeta potential measurements were indifferent between the crude oil and the core particles coated with crude oil. The wettability is not homogeneous although the presence of oil on rock surface changes wettability.

Filter cake formed by barite-based drilling fluid is often soaked with chelating agent removal treatment 24 hours to be dissolved after the drilling operation. During the removal process, the chelating agent absorbs barite from the filter cake to form a barite chelate. Due to the heterogeneity of the filter cake thickness where the thinner parts may dissolve faster and due to long soaking time, the removal fluid will have more time to invade the formation. This paper investigates the interaction between the barite chelate and the calcite formation after filter cake dissolution. The barite filter cake was formed over the face of calcite rock samples using a High-Pressure High Temperature (HPHT) fluid loss apparatus. Chelating agent solution was then used to dissolve the filter cake. NMR spectroscopy and X-ray CT images were applied to study the changes in the pore size distributions of the calcite rock samples at pre and post-invasion states. The result of this work showed that barite chelate released barite precipitates into the pores of the cores and then absorbed Calcium cations from the rock minerals. The barite chelates released barites into the macropores and absorbed cations from the micropores. CT scan and spatial NMR analysis also showed that the chelating agent was not able to create wormholes after releasing barite. A detailed explanation of the observed results is presented with supporting results. Based on the obtained results in this work, several recommendations were drawn for removing the barite filter cake in the filed application without causing any severe secondary formation damage.

Acid stimulation in low permeability carbonates is challenging and the performance depends on a good choice of acid recipe and comprehensive testing that supports the extent of wormholes or fracture patterns. In this paper, a comprehensive testing proposal that involves initial enhancements to reaction kinetic for organic, inorganic and composite recipes and later supported by core tests to quantify optimized pore-volume to breakthrough (PVBT) times for optimum worm-hole propagation is discussed. A protocol is demonstrated that outlines important tests, analysis and recommended practices to select efficient acid recipes for enhanced stimulation performance in low permeability carbonate reservoir. This protocol demonstrates that the design of efficient acid recipes should take into consideration: rock characteristics, lithological distribution, mineralogy, petrophysical qualities and petrographic information. A summary of tests, procedures and success criteria demonstrates the benefits of an integrated testing approach prior to deploying acid stimulation. Outlined in this work are important tests, analysis and recommended practices to select efficient acid recipes for enhanced stimulation performance specifically high rate matrix acidization (HRMA) in low permeability carbonate reservoir. These recommendations demonstrate the benefits of an integrated procedure for achieving superior well productivity, costs savings, operational flexibility and long term applicability that addresses subsurface and operational requirements for acid stimulation. This system is considered in offshore environments where logistics and cost are important in designing a stimulation strategy and is also applicable to onshore environments. Some key findings are that under simulated reservoir conditions and similar rock properties chemical or/and physical retarded acid provided deeper wormhole results from PVBT point of view than straight acid. Viscoelastic aicd (VES) diverter acid on the other hand showed deeper penetration by lower PVBT which will demonstrate efficiency based on the viscosity. The increase in viscosity could increase bottomhole (BH) pressure limiting matrix regime applications. Three Single Phase Retarded Acids (SPRA) were tested and all demonstrated excellent wormhole penetrations and improved benefits in terms of offshore logistics due to their reduced volumes, reduced viscosity and environmental benefits.

The evaluation of carbonate cores is a complex task because of the inherent heterogeneities that occur at all length scales. Rock properties may be defined differently at different scales and this introduces a challenge in capturing the heterogeneity in a single rock volume. This research work studied whole core samples using multi-resolution imaging and advanced computations. The samples could not be directly measured by conventional techniques due to their fractured state and complex nature. The cores are Mid Cretaceous in age, derived from a giant oil field in the Middle East and are predominately composed of limestone with complex paragenetic history. The core samples were first imaged by X-ray dual-energy CT in 3D at a resolution of 0.5mm/voxel. The whole core CT images revealed extreme heterogeneity along the sample lengths and showed varying distribution patterns of high and low-density textures. The selected plugs from those density textures were acquired to accurately represent the different flow phases in the whole core samples. The plugs were fully characterized by high-resolution X-ray CT images at 40 μm/voxel, thin-section photomicrographs, poroperm measurements and Mercury Injection Capillary Pressure (MICP). These analyses provided a detailed understanding of the geological and petrophysical variations within the different density textures in the whole core samples. Simultaneously, smaller-scale subsamples were obtained from the different porosity regions in the plugs and scanned at higher resolutions down to Nanoscale at 0.064 gm/voxel. The measured plug porosity and permeability data provided accurate results in the low and high-density regions in the whole core samples. This data was then upscaled to the whole core images by populating the individual data in the different textures and solving for the Stokes equation using the Lattice Boltzmann simulation. The upscaling process accounted for the varying fractions of the flow units in the sample, their interaction and their effects on the overall whole core properties. The dual-energy CT scans along with core visual inspection, thin-section photo-micrographs and mercury injection pore throat size distributions (PTSD), demonstrated that each density region had similar geological and fluid flow characteristics throughout the core intervals. The upscaled poroperm data for all the core intervals gave a linear trend with a clear increment of porosity and permeability as a function of the low-density phase in the core. The permeability KV/KH anisotropy ratios were digitally computed for all the core intervals and were found to vary from 0.44 up to 0.94, which reflects the relative presence and distribution of the high and low-density regions in the reservoir core samples. The digital analyses of the data together with the effects of heterogeneity distributions in the core provided an improved understanding of the geological and petrophysical properties in these complex reservoir rocks that would not be possible by conventional methodologies. The analyses were carried out at the pore scale and the core scale, which would lead to more robust reservoir engineering applications and petrophysical modeling of such complex reservoirs.

Recent experimental studies show that fines migration effect in sandstone rocks is more prominent at higher temperature. However, increased fines migration is generally attributed to temperature dependant zeta potential. In this study, laboratory studies were designed to investigate if mineral dissolution induced more fines migration at high temperatures. In this experimental study, Berea sandstone core samples are used and performed single-phase flooding experiments at three temperatures, 25°C, 50°C and 70°C. Core samples are characterized using X-Ray Powder Diffraction (XRD) and X-Ray Fluorescence (XRF) before the flooding experiments. Scanning Electron Microscopy (SEM) and Energy Dispersive X-ray Spectroscopy (EDS) analysis are also conducted to identify the changes of rock surface before and after the flooding experiments. All core samples are subjected to single-phase injections of water at salinities 40, 10, 2.5, 0.5 and 0g/L NaCl. To calculate permeabilities, pressure drops are recorded using pressure transducer during the flooding experiments. The produced water is collected and used to measure the concentration of produced fines. Inductively coupled plasma-optical emission spectrometry (ICP-OES) is applied to analyze the types of produced minerals in each experiment. The analysis of produced water showed that an increase in Ca ions at 50°C and 70°C. Chemical reation led to dissolution of carbonate minerals increasing pore opening. Therefore, the permeability damage due to fines migration is less pronounced at high temperatures.

In line with PETRONAS commitment to monetize high CO 2 content gas field in Malaysia, C Field which is a carbonate gas field located in East Malaysia's waters with approximately 70% of CO 2 becomes main target for development because of its technical and economic feasibility. Injectivity has been determined as one of the key parameters that determine the success of CO 2 storage in field operations. In order to characterize the CO 2 injecitivity behavior in C Field, long duration coreflooding experiments has been conducted on two representative core samples under reservoir conditions. The first set of coreflooding test has been conducted on gas zone sample and another one is on aquifer sample. Two important approach has been applied in the experiment in which the first one is where the base rate is established after each incremental stage and the second one is the pre-equilibration of carbonated brine with standard minerals based on the percentage of core mineralogy before saturating the core with aquifer brine to mimic the insitu geochemical conditions of the reservoir. Pre- and post-flooding characterization was conducted using Routine Core Analysis (RCA), X-Ray CT-scan, Nuclear Magnetic Resonance (NMR) and Inductive Coupled Plasma (ICP) to examine the porosity-permeability changes, pore size alterations and the geochemical processes that might take place during CO 2 flooding. Based on the differential pressure data, it showed no clear indication of formation damage even after injection of large CO 2 pore volume. Pre and post-flooding characterization supported the findings where minor dissolution/precipitation is observed. Overall intrepretation indicates that the critical flowrate is not yet reached for both samples within the maximum rates applied.

Investigation of the effectiveness of matrix stimulation treatments for removing drilling induced damage in Akita region in northern Japan is of interest due to the presence of large quantities of acid-sensitive minerals, such as analcime. Feasibility study of the sub-commercial field redevelopment in the Kita-Akita oil field, one of the satellite fields of main Yabase oil fields, which produced from 1957 to 1973, and were plugged and abandoned, were conducted. As a part of the studies, matrix acidizing laboratory experiments were performed. Conventional mud acids and formic-based organic mud acid systems cause significant permeability damage due to instability of analcime in these acids. This study focuses on the development of a treatment fluid that removes drilling-induced damage and is also compatible with the formation. Petrology studies and core flow tests were used in conjunction with geochemical modeling to achieve this objective. A petrographic analysis on the untreated cores showed abundant tuffaceous pore-filling mineral phases, ranging from 12 to 20% in volume. Smectite clay and microcrystalline quartz are the major constituents as alteration products of volcanic glass. Analcime was present in significant quantities in all samples tested. Six core flow tests were performed on formation cores to optimize the acid preflush and main acid stage. Permeability change due to the treatment fluids was recorded for the tests. Chemical analysis of the effluent was performed on three core flow tests. Core samples before and after acidization were characterized based on thin section, X-ray diffraction (XRD), scanning electron microscopy(SEM) and mineral mapping. Core flow tests with a conventional retarded organic mud acid resulted in only a 75% retained permeability. The permeability damage by the retarded organic mud acid was surprising because it usually performs well in acid-sensitive formations. A chelant based retarded mud acid was tested next and resulted in minor formation damage. It can potentially be used in a field treatment as its high dissolving power is expected to more than compensate for the damage. The highest retained permeability was obtained with an acetic-HF acid system. It was successfully able to remove drilling-induced damage and was also compatible with the native mineralogy. Core flow tests were used to calibrate permeability-porosity relationship used in the geochemical simulator. The geochemical simulator was then used to predict field-level acid response. The analytic methods presented are general enough to be of interest to sandstone acidizing studies where detailed analysis is needed for damage identification and removal. The fluids developed for this formation area good candidates for other formations where conventional acid systems have not performed well. This study also highlights close collaboration between an operator and service company to find a workable solution to a challenging stimulation requirement.

Due to the apparatus restrictions the resolution of the micro-CT scans of rock samples and the size of the 3D image are strictly connected. Thus improve in the resolution giving more detailed representation of the rock structure reduce the size of the sample, so that it goes below the representative volume for the estimation of a particular property. In this paper we study four 3D images of different resolution of Bentheimer sandstone. We show that the geometrical and statistical properties of the images (pore-to-core distribution, porosity, specific surface area, topology) can be stably reconstructed from the images of about 100 voxels. However, numerical estimation of the physical properties, such as permeability, requires larger images. To overcome this difficulty we suggest using statistical simulation of the sampels, based on the stably recovered information – image properties. In this paper we considered the simplest method of statistical simulation; i.e. truncated Gaussiam technique, which is based on the information about the total porosity and correlation length of pore-to-core distribution. This approach underestimates the specific surface area of the pore space, but the permeability of the sample was matched accurately.

Spontaneous imbibition is an important process to increase oil recovery in fractured carbonate reservoirs. Due to the nano-scale pores and throats distributed in tight oil reservoirs, capillary pressure became much larger, which may result in a much stronger imbibition. An experimental and modeling was adopted to simulate drainage and imbibition process in hydraulic fractured tight oil reservoir. Firstly, 400 mm×100 mm×30 mm core samples were used to simulate forced displacement and spontaneous imbibition of fracture surface at in-situ conditions of pressure. Secondly, 1D model for counter-current imbibition was solved on some assumption of relative permeability and capillary pressure, numerical results obtained by COMSOL as verification. Results have indicated that recovered oil was 0.19 mL in spontaneous imbibition condition while was 0.62mL in combined condition of forced displacement and spontaneous imbibition. Saturation front contacts the sealed end-face much faster with forced pressure condition. According to this phenomenon, it can be inferred that the main direction of aqueous phase in the shut-in period is form large pores to smaller pores. Aqueous phase was pushed into the large pores by forced pressure, and imbibed into smaller pores in the function of capillary pressure. 1D model of 2 phases counter-current imbibition solved with Galerkin method is in correspondence with numerical result at the same assumption. With the increase of dimensionless distance (X) and dimensionless time (T), water saturation profiles were drew and were contrasted with CT scanning. Forced displacement and spontaneous imbibition simultaneously occurs during fracturing and shut-in duration. Study of this can provide a reference for soaking management and a good way to increase well productivity.

Sand production is a major problem to the petroleum industry. Various methods and techniques including mechanical and chemical methods have been proposed but some have failed and some have been ineffective to control the sand production. In the present study a new chemical composition is evaluated to its ability to consolidate the loose sand by increasing its compressive strength without much loss in absolute permeability For the present study, an experimental setup is designed to consolidate the sand by injecting required PV of chemical solution into the sand pack. All the experiments are done in both presence and absence of hydrocarbon to insure reservoir condition. Effects of chemical composition, curing time, temperature on compressive strength and retained permeability of the consolidated sand is evaluated. Analytical techniques such as FT-IR, FE-SEM, and TG/DTA are used to study the interaction of chemicals with the silica sand sample. The effect of pressure drawdown and flowrate on the consolidation is also studied. The present mixture shows better consolidation capacity with an unconfined compressive strength (UCS) of >2500 psi with permeability retention greater than 80%. Thus, the consolidation treatment provides the great compressive strength with such permeability retention so that we can take production economically. The curing temperature and time is optimized as 80°C and 12 h respectively. Analytical technique proves a significant binding at the contact point of the sand particles. The consolidation withstand the differential pressure up to 2700 psi and the critical flowrate was recorded as 151.31 cc/sec. the consolidation can hold the pressure drawdown greater than its compressive strength. The present study comprises the evaluation of a new chemical composition to consolidate the loose sand at their contact point so that it can withstand the drag forces induced by the reservoir fluids and other induced forces.

Average recovery factor in offshore field under discussion is relatively moderate due to wider well spacing and poor sweeping efficiency thus leaving significant volume of oil behind in the reservoir. Timely application of EOR is therefore necessary to enhance the recovery factor to a reasonable level. Among the various EOR processes and techniques of EOR screened, studies found immiscible water-alternating gas (IWAG) injection as the most suitable and viable option for this Malaysian mature offshore oilfield. Realistic estimate of incremental oil by EOR is paramount as IWAG application involves high CAPEX and OPEX project. Therefore, representative is required to be generated in the laboratory for constructing a realistic reservoir simulation model to understand the three phase flow in porous media and support the IWAG process for full field implementation. Important parameters in this case are residual oil saturations in sequential injection of displacing fluids water and gas and trapping of gas, injection volumes and frequency of alteration. Therefore, IWAG core flooding experiments under reservoir conditions need to be performed, results quantified and parameters for hysteresis modeling established. This paper addresses the challenges and strategies of IWAG core flooding experiment performed under reservoir conditions using representative composite native cores, live reservoir oil sample, field produced gas sample and synthetic formation brine water. The laboratory injection rates are considered equivalent to the field fluid advance velocity like in any standard displacement steps. Also, gravity stable injection mode is considered to achieve the best IWAG displacement performance. These challenges and strategies are drawn from lessons learned during accomplishment from earlier IWAG core flooding experiments. The IWAG core flooding experiments were performed on composite field core samples, arranged according to Langaas method, using current field production gas with 60 mole % CO2. The composite reservoir core samples were initially saturated with live oil and irreducible formation water and then flooded with formation water and seawater to residual oil saturation at reservoir conditions. Following, waterflooding, a number of water and gas cycle slugs were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure during these experiments. Laboratory studies and numerical simulation study conducted on the applicability of immiscible WAG injection using high CO2 content produced gas indicated that 7.0 % additional oil recovery over waterflooding period can be recovered.

Carbon Capture and Storage (CCS) is particularly attractive for the oil and gas industry due to the potential of Enhanced Oil Recovery (EOR). The presence of adequate well injectivity is identified as a prerequisite for CCS and CO 2 EOR projects. Mineral precipitation in the vicinity of the well is suggested as a possible injectivity impairment mechanism. After mineral precipitation and formation dryout, continuous injection of CO 2 into the formation could redistribute precipitates and alter injectivity. In this work, we investigated the effect of viscous force on precipitated minerals and the resulting consequences on permability and injectivity. The influence of supercritical CO 2 injection rate, initial core permeability and saturating brine salinity were investigated. We observed that, injectivity impairment has a maximum immediately after mineral precipitation. Continuous injection of supercritical CO 2 into the core after mineral precipitation is seen to reduce injectivity impairment induced by precipitated minerals. In most numerical and geochemical models, static injectivity impairment as a result of mineral precipitation is often assumed. Our findings suggest that injectivity remains dynamic throughout the injection process. Therefore, changes in CO 2 injectivity after mineral precipitation could be complex to model and understanding of the processes is a good point to start.

A well-designed acid stimulation treatment is a rapid well intervention operation that can lead to long-trim economical benefits. In carbonates, the main challenge is to better design acid stimulation treatments in order to meet the two main characteristics of carbonate reservoirs which are high water production and a wide range of heterogeneities. Acid diversion is one of the key factors for a proper distribution of acid which determines the success of these treatments, especially in heterogeneous carbonate formations. In this study, we aim at producing novel solutions in order to reduce water production and enhance zonal coverage through effective diversion. The ultimate goal is to validate a single pumping sequence that combines water mitigation, diversion and acid injection. In order to achieve this, we rely on an integrated R&D approach combining single core and dual core experimental setups. The advantage of the dual core setup is to investigate different permeability contrasts, different saturations configurations and to experimentally validate wormholing in heterogeneous carbonates. In fact, in carbonate effective diversion happens when acid is flowing in the low permeability area at sufficient velocity . An easy way to validate this is through parallel core flooding. We performed a series of high pressure and temperature single and dual core flooding experiments over a range of different carbonate samples having different permeability and porosities. The injection took place at 90 °C and 250 bars. We assessed the efficiency of polymer adsorption by measuring permeability during, before and after polymer injection. Computed Tomography scans were used in order to validate our conclusions. We showed that, adsorption of polymer in carbonates is possible but needs careful design. We experimentally investigated acid diversion in high permeability contrasts (matrix-fissures) through core flooding. This is another novelty in this study. Finally, the combined pumping sequences were experimentally assessed. We validated diversion in carbonates and identified the optimum injection rates required for such applications. An optimum configuration of permeability contrasts and saturations exists for a combined pumping sequence. The experimental results and observations are translated into a series of guidelines and procedures which are directly applicable to acid stimulation field operations. The areas of future required research in applied fluid-rock interactions will be highlighted.

In an energy hungry world, fossil fuels are predicted to remain the dominant source of energy for a long time. Burning more fossil fuels will increase CO 2 emissions in the atmosphere and will consequently increase the challenges of climate change mitigations. Carbon capture and storage (CCS) in deep saline aquifers is an important process for CO 2 reduction on industrial scales but it is not economically attractive. Residual trapping of CO 2 through capillary forces within the pore space of the reservoir is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO 2 migration within the reservoir. Carbon capture, utilization and storage (CCUS) in mature oil reservoirs can have a significant energy, economic and environmental benefits and is considered an important component in achieving the widespread commercial deployment of CCS technology. Residual trapping in mixed-wet systems, however, is assumed to be less efficient than in water-wet systems. In this study, we compare residual trapping efficiency in water-wet and mixed-wet carbonates systems on the same rock sample before and after wettability alteration by aging with crude oil. The observations were made at reservoir condition in a core-flooding system that included high precision pumps, temperature control, the ability to recirculate fluids for weeks at a time and an x-ray CT scanner for in situ saturation monitoring. The wetted parts of the flow-loop are made of anti-corrosive material that can handle co-circulation of CO 2 and brine at reservoir conditions. We report the initial-residual CO 2 saturation curve and the resulting parameterisation of hysteresis models for both water-wet and mixed-wet systems. A novel core-flooding approach was used, making use of the capillary end effect to create a large range in initial CO 2 saturation in a single core-flood. Upon subsequent flooding with CO 2 -equilibriated brine, the observation of residual saturation corresponded to the wide range of initial saturations before flooding resulting in a rapid construction of the initial residual curve. Also, multiphase flow observations were made on a single carbonates core sample. It was made first on its original water-wet state, then were measured again after altering the wetting properties to a mixed-wet system. In particular, CO 2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly.

Abstract Hydrocarbon production optimization in Pre-Salt carbonate reservoirs is a main focus for oil and gas research in Brazil. Stimulation treatment design optimization requires good knowledge of the reservoir properties and excellent understanding of the interaction between rock formation and treating fluid. This paper investigates these interactions through laboratory tests determining the compatibility of fluids used in matrix stimulation with different Pre-Salt carbonate rock types. The objective of this work is to relate the geology, petrophysics, and geomechanics of the Pre-Salt reservoirs to their expected stimulation response. Because of the difficulty in obtaining downhole cores and the destructive nature of most tests, the study focused on samples collected from a Pre-Salt carbonate analog: the Coquinas formation (Schafer 1973) from the Sao Miguel quarry, northeast Brazil (Chagas de Azambuja Filho et al. 1998). A thorough geology-based study of the Coquinas formation, including routine core analysis (FZI) microtomography, and thin section study was conducted. Usually these grain-supported carbonates show different amounts and types of primary porosity, closed and reopened by multiple diagenetic phases. Throughout the 25-m thick Coquinas reservoir, five rock types in 13 layers with permeability ranging from microdarcy to almost 1 darcy were identified. All rock types were subjected to routine mineralogy evaluation and various petrophysical, geomechanical, and spectroscopic measurements. Six of the thirteen layers were selected to perform core flow tests with a viscoelastic surfactant technology based diverting acid fluid (Al-Mutawa et al. 2005; Chang et al. 2001; Samuel et al. 1997). This is the first extensive study reporting the efficiency of a viscoelastic diverting acid system in the Pre-Salt analogue Coquinas carbonate formation outcrop cores. Spectroscopic measurement showed wormhole creation and, in some cases, rock texture alteration or fine migration. Through the study we identified the flow units and characterized the rock behavior when chemically stimulated. The conclusions from this study will enable us to tailor and optimize stimulation treatments of Pre-Salt carbonate reservoirs. Introduction The offshore Pre-Salt in Brazil comprises a group of recently discovered fields with promising oil reserves in the Coquinas formation or the above the microbialites section. For example, Lula (ex-Tupi) field, the lead field of the Santos cluster, is believed to hold between 5 to 8 billions barrels of oil equivalent (Beltrao et al. 2009). The Pre-Salt reservoirs are currently the focus of research in Brazil; however, the scarceness of downhole samples collected makes destructive tests very difficult to perform, and so analysis must be performed on analogues. The onshore Coquinas formation from northeast Brazil is taken here as analogue of the Pre-Salt carbonates.

Abstract A number of Malaysian mature oil fields have been and are still under investigation for Enhanced oil Recovery (EOR). This includes Water Alternating Gas (WAG), chemical flooding and Foam assisted WAG. This field is one of the most fields under extensive EOR studies for WAG & FAWAG. Despite the promising recovery factor from EOR application there are always the side effects that accompany these processes which are formation damage and injectivity issues. A lot experiments studies shown, when a large number of pore volumes of polymer is injected with medium permeability beyond a critical shear rate, a plugging tendency is observed. This plugging is attributed to a damage mechanism called "bridging adsorption" in which stretched polymer macromolecules form numerous bridges across pore throats. At the same time, causes fine migration issue. In this study, the effects of fines migration, clay swelling and injectivity were investigated in separate core floods studies (one test for fines migration, one test for clays swelling and three for chemical injectivity). For the fines migration study, the core flood test to investigate the critical flow rate of the seawater injection shows fines migration problem as observed from sea water injection of intermediate critical flow rate for fines migration in the core. For clays swelling the permeability reduction test and pH measurement with decreasing salinity indicates a critical salinity much less than the sea water salinity and sea water is the proposed medium for the EOR chemical in this field. Moreover, SEM investigation analysis result shows that most of the damage is due to fine migration caused by the velocity flow rate of the injection sea water. For injectivity study, core flood tests were conducted with injecting surfactant polymer (SP) solution and with surfactant and polymer individually. The results show that while minimum damage of less than 30% is typically expected in this type of test with permeability resistance factor of less than 3, what was actually obtained in this test is about 95% damage and permeability resistance factor (PRF) is 23 compared to KPI of 3. The results also indicate that incompatibility between the surfactant and polymer could be one of the reasons for permeability decline. This is because while injecting the chemicals separately no serious injectivity issue is observed. Introduction EOR studies prior to field application have recently enjoyed global attention due to several reasons including declining oil production below par primary and secondary recovery, high crude oil price and increasing energy demand which is growing at approximately 1.5% per year (Du, K., et al, 2011). Laboratory testing in support of field application is critical to minimize field application failures. This paper addresses possible risk of formation damage due to fine migration, clay swelling and polymer absorption during Foam Assisted Water Alternating Gas (FAWAG) process proposed for the field. The offshore field is located 170 km away from West- Malaysia land. Currently this field is being considered for enhanced WAG process called Foam assisted Water Alternating Gas (FAWAG). In this process it is proposed to alternate polymer surfactant with gas instead of water. Surfactant is proposed to precede the gas injection, which will generate foam in-situ. Foam so generated along with the polymer is expected to improve the displacement efficiency by virtue of better mobility control, once implemented, This field will be the first such application in Malaysia.

Abstract The existing method to infer relative permeability from resistivity data was modified by including more parameters such as residual oil saturation. Both oil-water relative permeability and resistivity were measured simultaneously in the same core sample at a room temperature in order to verify the modified model. Altogether 16 core samples in 2 wells from Daqing oil field, China have been tested. The permeability ranged from about 10 to 800 md. The oil-water relative permeability data were measured using a dynamic displacement technique. Oil-water relative permeability data were inferred from the resistivity data measured in the laboratory and logged from the well using the modified model. The model data were then compared to the experimental data. We demonstrated that the relative permeability of both oil and water calculated from the resistivity data measured in the same core samples and logged from the same wells were close to the experimental data measured using a dynamic displacement approach. The modified model had a greater accuracy compared with the existing models. Using the modified model, it would be possible to obtain the different distribution of relative permeability characteristics in different kinds of formations in a reservoir. It may also be feasible to infer relative permeability data while drilling if resistivity well logging is being taken. Introduction Relative permeability is one of the important parameters controlling multiphase fluid flow in porous media. These data are traditionally obtained with experimental measurements. However, relative permeability is expensive, difficult, and time-consuming to measure in the laboratory, especially for the rocks from unconventional oil and gas reservoirs such as shale plays, tight sands, and extremely low permeability reservoirs. It is also difficult to maintain exact reservoir conditions in taking a core or a fluid sample from the reservoir and bringing it to surface and it is almost impossible to conduct the measurements in real time. Consequently, there has been a decades-long research effort to develop methods and procedures to infer relative permeability using network modeling. Recently, the industry has been researching new methods to extract relative permeability in-situ including the utilization of specially designed permanent downhole electric resistivity array, pressure, and flow rate measurements. Relative permeability can also be derived from other parameters such as capillary pressure data. Mahmoud et al. (2013) predicted the capillary pressure from well logging data in carbonate reservoir and sandstone reservoir. Purcell (1949) reported a mathematical model to calculate the relative permeability from capillary pressure data. From then on, many researchers worked on this area. Li (2005, 2007 and 2010), Li and Horne (2006) and Li and Williams (2006) have made a lot of contribution for estimating the relative permeability using resistivity well logging data. Based on the reaserch on the interrelation between capillary pressure, resistivity and relative permeability reported by Li (2010), Alex et al. (2012) considered to modify the model in double porosity systems. They developed a method to calculate relative permeability and caplillary pressure from resistivity well logging data in naturally fractured reservoirs.

Keshen reservoir is a deep, tight gas sandstone reservoir under high tectonic stress with reservoir pressure over 16,000 psi (110 MPa) and temperatures up to 165 °C. Development wells for this field are in excess of 6500m in true vertical depth. Stimulation is required to provide production rates that compensate for the high cost of drilling and completing wells. Hydraulic fracture design and execution must be optimal to ensure economic production. To effectively stimulate a more than 200 m thick sandstone reservoir with consistently high performance, it is necessary to understand the mechanical behaviour of the reservoir, especially mechanical properties and in-situ stresses as the two control initiation and propagation of each hydraulic fracture. The mechanical behaviour is complicated by high tectonic stresses, significant compaction, and high overpressure. To gain an in-depth understanding of the mechanical properties and in-situ stresses of Keshen reservoir, an integrated geomechanical evaluation was conducted. The evaluation used core from two wells, KS205 and KS207, and log data obtained from 15 wells including the wells with core evaluation in the field. A laboratory testing program to investigate the mechanical behavior of the reservoir sandstone under realistic in-situ stresses, pore pressures, and temperature was performed. The description of mechanical behavior obtained from the laboratory testing was used to calibrate and augment mechanical earth models (MEMs) constructed from well log data. The reliability of the completed MEMs was validated through comparison between wellbore stability predictions with observation of borehole failure from the borehole microresistivity image. The geomechanics information was delivered to the stimulation engineering team. Hydraulic fracture design and execution was conducted based on this information. The outcome of hydraulic fracturing was very encouraging. This study demonstrated that successful stimulation of tight reservoir in high pressure, high temperature relies on integrated geomechanical analysis.

Abstract Injection of CO2 into the subsurface is of interest for CO2 storage and enhanced oil recovery (EOR). There are, however, major unresolved questions around the multiphase flow physics and reactive processes that will take place after CO2 is injected, particularly in carbonate rock reservoirs. For example, the wetting properties of CO2-brine-rock systems will impact the efficiency of EOR operations and CO2 storage but reported contact angles range widely from strongly water-wet to intermediate wet. Similar uncertainties exist for properties including the relative permeability and the impact of chemical reaction on flow. In this presentation we present initial results from laboratory studies investigating the physics of multiphase flow and reactive transport for CO2-brine systems. We use traditional and novel core flooding techniques and x-ray imaging to resolve uncertainties around the CO2-brine contact angle, relative permeability, residual trapping, and feedbacks between chemical reaction and flow in carbonate rocks. Introduction Uncertainty around CO2 storage and EOR may be significantly reduced from a greater understanding of the fundamental physics of fluid flow and reactive transport that control rock-brine-CO2 interaction in the subsurface. The combination of unique multiphase flow properties and significant reactivity in the CO2-brine-carbonate rock system has major impacts on the injection, flow and immobilization of CO2 in the subsurface. These unique properties must be accurately characterized to reduce major uncertainties for CO2 storage and EOR in carbonate rocks. Observations of reservoir condition multiphase flow and reactive transport properties for the CO2-brine-carbonate rock system are provided including wetting properties, capillary pressure, relative permeability and residual trapping. A methodology is presented for utilizing a combination of novel and traditional core-flooding and imaging techniques for a comprehensive characterization of carbonate reservoir rock.

Abstract Digital rock physics (DRP) has received considerable attention in recent years as an alternative to laboratory measurement, especially for the prediction of reservoir properties for which the right laboratory measurements are difficult to perform or require long measurement times such as the special core analysis (SCAL) properties relative permeability and capillary pressure. While measurement of these reservoir properties can certainly be challenging to execute, there is a long history of successful, high-quality laboratory SCAL measurements. Before adoption of a DRP approach to generate reservoir properties that have significant impact on expected reservoir performance, it is important that the uncertainties introduced by use of DRP are better understood. To this end, we have utilized samples from a large Middle Eastern carbonate reservoir to benchmark vendor DRP predictions of water-oil imbibition relative permeability and capillary pressure against high-quality SCAL results that were measured using consistent laboratory methods. Considerable scatter are observed in the DRP predictions that do not exist in the measured SCAL data and cannot clearly be attributed to sample heterogeneity. Wettability, which is an important input into digital rock predictions but is especially challenging to quantify in the laboratory, is shown to have a significant impact on DRP predictions of relative permeability and capillary pressure. Nevertheless, the dependence of the DRP results on wettability is inconsistent with the SCAL data. Given the additional scatter and inherent uncertainties associated with use of the DRP approach, we find that a high-quality laboratory program employing consistent test methods remains the best approach to obtain SCAL data to support reservoir definition development, and depletion objectives. Introduction Accurate, high-quality special core analysis (SCAL) data (e.g., relative permeability and capillary pressure) are integral to reservoir performance prediction and effective reservoir management. Achieving high-quality SCAL measurements in the laboratory is by no means an easy task, but can be accomplished provided that four key requirements are met: measurements must be on rock samples representative of the reservoir (the right samples), measurements must be made under conditions representative of displacement processes in the reservoir (the right conditions), measurements must be made using the appropriate test methodologies and using precision equipment and techniques (the right equipment), and trained and experienced technologists are needed to ensure that appropriate samples are selected, to conduct the measurements, and to model the data (the right people). Several prior publications elaborate on the four key requirements (Braun 1981, Gomes 2008, Hassler 1945, Honarpour 2006, Honarpour 2005, Honarpour 2004, Johnson 1959, Wang 2008). It is important to note that both relative permeability and capillary pressure data are necessary to define displacement processes in reservoir simulation, and methods to measure and to integrate SCAL data should consider both types of data (Bhatti 2012, Kralik 2010, Meissner 2009).