A systematic approach to characterize the mixed wet configurations of various reservoir rocks (sandstone and carbonates) by evaluating their surface energy distributions has been presented in this paper. This approach was tested against the macroscopic spatial distribution of oil-wet and water-wet sites and at different temperatures for validation.
The new approach used to characterize the mixed wettability of a reservoir rock pertains to establishing a relation between the volume fraction of the mixed-wet reservoir rocks and surface energy of the mixture. This approach is based on an accurate description of the various physico-chemical interfacial forces present at the reservoir rock surface using Inverse Gas Chromatography (IGC). Mixed-wet configurations of various reservoir rocks are created by combining water-wet and oil-wet samples of the rock in different volume fractions and shaken together to establish uniform distribution. These samples are then subjected to the IGC analysis at different temperatures to deduce their surface energy distribution. The relation developed herein is tested against spatial heterogeneity by combining the oil-wet and water-wet rock samples in a layered fashion to validate the approach. The complete method to deduce the surface energy distribution of a rock surface using IGC has also been explained in detail.
A definite and conclusive relationship between the surface energy and mixed wettability of silica glass beads, calcite, and dolomite samples was established in this study. The mixed-wet configurations of the rock samples ranged from 0% oil-wet (meaning water-wet samples) to 100% oil-wet samples. The findings indicated that the Lifshitz-van der Waals component of the rock mixture did not undergo any change with change in the wetting state of the system under study. However the acid base components showed a marked decrease with increasing oil wetness before plateauing. Temperature was found to have a profound impact on the surface energy of a rock surface. Spatial heterogeneity by way of layered and segregated distribution of oil-wet and water-wet sites did not affect the eventual surface energy distribution thereby validating the new approach.
Sharma, Himanshu (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Recent studies on the use of ammonia as an alkali for performing alkali-surfactant-polymer (ASP) floods have shed light on its advantages over conventional alkalis such as lower alkali requirements, ease of transportation and storage. This study is aimed towards understanding surfactant adsorption in sandstone and carbonate rocks in the presence of ammonia. Zeta potential measurements were performed to characterize Bandera brown sandstone and Silurian dolomite surfaces in the presence of ammonia and sodium carbonate. A series of experiments were performed with and without ammonia such as static surfactant adsorption experiments on crushed Bandera brown sandstone and Silurian dolomite rocks, single phase surfactant transport experiments in sandstone and carbonate cores, surfactant phase behavior to identify an ultra-low interfacial tension (IFT) surfactant formulation, and oil recovery coreflood experiments using these surfactant formulations. Zeta potential measurements showed a reduction in zeta potential of Bandera brown and Silurian dolomite by adding ammonia to increase the pH. Surfactant adsorption experiments showed that ammonia was able to reduce the adsorption on sandstones, but not much difference was observed for carbonates. The ultra-low IFT surfactant formulations developed with and without ammonia showed very similar phase behavior. High oil recoveries and very low surfactant retentions were observed in the oil recovery experiments performed in sandstones.
Rohilla, Neeraj (TIORCO, a Nalco Champion Company) | Ravikiran, Ravi (Stepan Company) | Carlisle, Charlie T. (Chemical Tracers Inc.) | Jones, Nick (University of Wyoming) | Davis, Marron B. (Sunshine Valley Petroleum Corporation) | Finch, Kenneth B. H. (TIORCO, a Nalco Champion Company)
Sandstone reservoirs containing significant amount of clays (30-40 wt%) with moderate permeability (20-50 mD) provide a unique challenge to surfactant based enhanced oil recovery (EOR) processes. A critical risk factor for these types of reservoirs is adsorption of surfactants due to greater surface area attributed to clays. Clays also have high cation exchange capacity (CEC) and can release significant amounts of di-valents that lead to increased retention of the surfactant. These factors could adversely affect the economics of a flood.
We present a case study where a robust formulation was designed and tested in lab/field for a reservoir located in Wyoming, USA and contains up to 35-40 wt% clays (predominately Kaolinite and Illite). The residual oil saturation is high (Sor=0.4) while the permeability of the formation is between 20-50 mD. The reservoir has been waterflooded historically with low salinity water which has led to formation permeability damage. Due to high levels of clays, adsorption of the surfactant on the rock surface was determined to be between 3-4 mg/g rock by static adsorption tests.
This publication demonstrates how the following challenges have been successfully addressed in the lab as well as in the field in the form of single well chemical tracer test (SWCTT).
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity. Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation. Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine. Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front. Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity.
Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation.
Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine.
Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front.
Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Wettability of the rock is an important parameter in determining oil recovery. It determines the fluid behavior and the fluid distribution in the reservoir. Aging of the rock changes the wettability of the rock and can affect the residual oil saturation. This paper investigates the effect of aging on the oil recovery during the Water-Alternating-CO2 injection (WACO2) process using 20 in. outcrop Grey Berea sandstone cores under immiscible conditions.
In the present work, two coreflood experiments were performed. Both cores were aged for a period of 30 days at 149°F. This study is a continued research and compares the performance of WACO2 injection in aged cores to previously published work with unaged cores. All experiments were done at 500 psi and in the secondary recovery mode. The wettability of the Rock- Brine-CO2-Oil system for aged cores was determined by contact angle measurements using formation brine (174,156 ppm), seawater brine (54,680 ppm) and low-salinity brine (5,000 ppm NaCl). The interfacial tension (IFT) of the Brine-Oil-N2 and Brine-Oil-CO2 system was also measured using the axisymmetric drop shape analysis (ADSA) method. Computerized tomography (CT) scans were obtained for each core in its various states: dry state, 100% water-saturated state, oil saturated state with irreducible water saturation, and residual oil-saturated state. The CT scans were used to determine the porosity profile of the cores.
The contact angle measurements of the Rock - Brine - CO2 - Oil system indicated an increase in contact angles after the aging of the cores. Low-salinity brine showed the most water-wet state (55°) and seawater brine showed the most oil-wet state (96°) of the rock. This may be because of the increased concentration of divalent ions on the surface of the rock during seawater brine injection. Ion binding is the dominant mechanism in the oil-wet nature of the rock. The previously published work stated that the coreflood experiments of the unaged cores resulted in an oil recovery of 61.7 and 64.6% OOIP during low-salinity water-alternating-CO2 and seawater-alternating-CO2 injection, respectively. In aged cores, the oil recovery increased to 97.7 and 76.1% OOIP during the low-salinity water-alternating-CO2 and seawater-alternating-CO2 injection, respectively. The improved oil recovery was attributed to the wettability alteration when the rock was aged.
The interfacial tension measurements of brine/oil/nitrogen and brine/oil/CO2 systems showed that the salinity of the brine had an effect on the IFT. Low-salinity brine (5,000 ppm) yielded the highest IFT values and seawater brine produced the least. Monovalent ions had a weak effect on the interfacial activity between the oil and the brine. When multivalent ions were present, the IFT values were influenced by the salting effect of the brines. During the IFT measurements of brine/oil/CO2 system, the IFT values showed an increasing trend as a function of time and then stabilized. The increase in IFT was because of the initial mass transfer between the CO2, brine, and oil phases.
Dalmazzone, C. (IFP Energies Nouvelles) | Mouret, A. (IFP Energies Nouvelles) | Behot, J. (IFP Energies Nouvelles) | Norrant, F. (IFP Energies Nouvelles) | Gautier, S. (IFP Energies Nouvelles) | Argillier, J.-F. (IFP Energies Nouvelles) | Chabert, M. (SOLVAY)
A majority of the worldwide oil reserves is contained in carbonate reservoirs. Most of these reservoirs are naturally fractured and produce less than 10% of the oil in place during the primary recovery operations. It is noteworthy that this particularly low recovery ratio is essentially due to a low permeability associated to an intermediate or preferentially oil wettability. Consequently, the recovery of residual oil from these specific reservoirs is a great challenge. Changing the wettability from oil wet to preferentially water wet by using chemicals is one of the EOR technique that may be advantageously used to enhance the production rate. This chemical treatment consists in injecting an aqueous solution of surfactants or chemical additives to increase the water wettability and favour spontaneous imbibition into the porous matrix. We present a new test allowing a fast screening of aqueous solutions of chemicals that may be used to improve oil recovery from carbonate reservoirs. The test consists in depositing a drop of aqueous solution on a porous carbonate slice that has been treated to be preferentially oil wet before being put into dodecane. The evolution of the drop profile is then monitored as a function of time by means of a camera, which permits a simultaneous measurement of the interfacial tension between oil and water, contact angle between the water drop and the porous matrix and spontaneous imbibition. Various types of non-ionic and anionic surfactants belonging to different families have been tested and ranked to identify the best candidates among these chemicals. Finally, a Nuclear Magnetic Resonance technique was used to follow spontaneous imbibitions of selected candidates in miniplugs representative of the carbonate slices used in the screening test. NMR's results confirmed the classification issued from the fast screening test.
Alexis, Dennis (Chevron Energy Technology Company) | Varadarajan, Dwarakanath (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Winslow, Greg (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company)
Performance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP's through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM's. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability(<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.
Ansari, Arsalan A. (The Petroleum Institute) | Haroun, Mohammed (The Petroleum Institute) | Rahman, Mohammed Motiur (The Petroleum Institute) | Chilingar, George V. (University of Southern California)
The increasing global demand for additional energy requirement forecasted upto 74% in 2030 has made Improved Oil recovery (IOR) at the forefront of oil and gas R&D for the past 4 decades as it helps in the improvement of the hydrocarbon sweep efficiency. In carbonate reservoirs, there is a challenge of having large fractions of unswept oil, mainly due to permeability damage, heterogeneous formation or unfavourable petrophysical properties. Conventional acidizing, though useful in increasing the effective permeability in the near well-bore region, has issues of limited depth of penetration, as acid is consumed and adsorbed early into the formation. However, the application of Electrokinetic Low-concentration acid IOR (EK LCA-IOR), where conventional low-concentration acidizing (LCA-IOR) is coupled with electrokinetic enhanced oil recovery (EK-EOR) [
This study demonstrates an integrated approach using Single Energy Computed-tomography (SECT) scan imaging and Nuclear Magnetic Resonance (NMR) to analyze the compatibility and effectiveness of EK LCA-IOR in carbonate reservoirs through an increase in depth of penetration. Core-flood experiments at Abu Dhabi reservoir conditions conducted on 1-foot core-plug, involved waterflooding followed by LCA-IOR, assisted by electrokinetics in both sequential and simultaneous fashion, identifying optimum conditions (1.2% HCl concentration, 1V/cm voltage gradient).The use of SECT images of core-plug before and after the experiments, confirmed wormhole orientation and propagation length across heterogeneous core-plugs. NMR was used to identify and confirm various reservoir rock types (RRTs)that were tested allowing us to expand the range of optimum current densities and acid concentration for the EK LCA-IOR process to meet the objectives of this study in maximizing displacement efficiency and permeability enhancement.
Findings confirm EK LCA-IOR application resulted in additional 15–35% displacement efficiency beyond the waterflooding limit (60%). In addition, the maximum permeability enhancement of 53% was recorded and made possible using the simultaneous approach. SECT imaging confirmed that the maximum penetration depth of the injected acid was achieved using the simultaneous approach as the enhancement of depth of penetration was 82% and 70% in simultaneous and sequential approach, respectively. Furthermore, NMR results indicate that EK LCA-IOR is promising across heterogeneous formations, which allows us to optimize the process for each unique formation, using the identified operating parameters increasing displacement efficiency by 35% and permeability enhancement by 28%.
EK LCA-IOR may be developed as an environomic technology targeting the reduction of power consumption and acid/water requirement upto 70% as compared to conventional IOR processes. This study takes advantage of integrating imaging capability of SECT & NMR in order to couple particle mobility and zeta potential to assess the performance of EK LCA-IOR compatibility in Abu Dhabi carbonate reservoirs.