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Abstract Most chemical EOR formulations are surfactant mixtures, but these mixtures are usually modeled as a single pseudo-component in reservoir simulators. However, the composition of an injected surfactant mixture changes as it flows through a reservoir. For example, as the mixture is diluted, the CMC changes, which changes both the adsorption of each surfactant component and the microemulsion phase behavior. Modeling the physical chemistry of surfactant mixtures in a reservoir simulator was found to be more significant than anticipated and is needed to make accurate reservoir-scale predictions of both chemical floods and the use of surfactants to stimulate shale wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Mineral (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Planning for Large Scale ASP Flood Implementation in Mangala Oil Field
Pandey, Amitabh (Cairn Oil & Gas, Vedanta Limited) | Jain, Shakti (Cairn Oil & Gas, Vedanta Limited) | Prasad, Dhruva (Cairn Oil & Gas, Vedanta Limited) | Koduru, Nitish (Cairn Oil & Gas, Vedanta Limited) | Raj, Rahul (Cairn Oil & Gas, Vedanta Limited)
Abstract A highly successful ASP flood pilot has been conducted in the Mangala oil field in the Barmer basin located in the Rajasthan state of western India. The field which contains paraffinic oil with ~15cP oil viscosity is currently under full field polymer flood. The field has a STOIIP of ~1300 mmbbls and has already achieved more than 30% recovery factor in 10 years of production since coming online in 2009. The ongoing polymer flood is performing satisfactorily and the objective of large scale ASP implementation is to arrest the projected production decline and improve the ultimate recovery from the field. A normal 5-spot ASP pilot was conducted in the topmost reservoir of the field during the year 2014-15. The ASP formulation contained surfactant combination of high molecular weight TSP-EO-PO-sulfate and high carbon number ABS. The pilot was highly successful with estimated incremental recovery by ASP injection of more than 20% of the pilot STOIIP over polymer flood. The water-cut in the pilot dropped from more than 90% to levels of 20-30%. Comprehensive modeling of the corefloods and the pilot performance helped to calibrate the chemical flood simulator which was used for the development of large scale implementation concept. Various produced fluid related studies helped to design the surface facility concept. Given that large volumes of chemicals will be used, work is ongoing to define the chemical procurement strategy. The sector level modeling studies indicated that closer spacing improves the response time and helps to maximize the reserves in a given time frame. The study identified that infill drilling to convert the existing 5-spot polymer flood pattern into a direct line drive pattern is an optimal concept. The modeling study in combination with the surface facility considerations helped to design the expansion approach. The slug size sensitivity suggested to use slightly bigger pore volume of ASP slug in the range of 0.4-0.6 PV taking into consideration heterogeneity uncertainties attached with flooding multiple sands in fluvial deposition. The facility studies using the pilot information and additional lab studies helped to design the surface facilities concept. Requirement of produced water reinjection and water softening of the water for ASP injection in combination with anticipated scaling and produced fluid separation issues posed significant challenges. The paper will present the development journey of a very large scale ASP implementation concept in the Mangala field with focus on modeling at core/pilot/sector/full-field scale. The uncertainties associated with modeling of complex mechanism of the process will also be discussed. A high level surface facility concept and chemical procurement strategy will also be presented. This would be one of the few case history of a very large scale ASP implementation planning project.
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.34)
- Geology > Mineral > Sulfate (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Abstract The ASP process may still be promising for surfactant flooding of shaley formations that have high surfactant adsorption with conventional surfactant-polymer flooding. Positive sites on clays are sites where anionic surfactant adsorption occurs in conventional surfactant flooding. High pH of alkali converts positive clay sites to negative sites. In addition, sodium carbonate sequesters calcium ions due to the small solubility product of calcium carbonate. If the formation has pyrite or siderite present, the core material in the laboratory environment will likely have a coating of ferric oxide that contributes to the anionic surfactant adsorption sites. Thus the test core should be restored to reducing conditions to better represent in situ conditions. The ASP process has two sources of surface active materials. One is injected synthetic surfactant and the other is soap generated in-situ by reaction of alkali with naphthenic acids in crude oil. However, this adds to the complexity of the process because the optimal salinity becomes a function of both the concentration of injected surfactant and in-situ generated soap. Water soluble active soap number (WSASN) is used instead of total acid number (TAN) to estimate the optimal salinity. When WSASN rather than TAN is used to estimate the soap content, the logarithm of the optimal salinity is a linear function of the soap fraction. In this presentation, we demonstrate the technology to estimate the optimal salinity of soap/surfactant mixtures and use it to develop formulations with great potential to recover oil for a weakly consolidated sandstone reservoir. The potential of incremental oil recovery by the ASP formulation is evaluated by ASP flooding tests on both quartz sand packs and formation material. The ASP formulation recovered more than 95% of the water flooded residual oil using a 0.5 PV slug of either 0.3% or 0.5% NI blend surfactant. The sodium carbonate concentration was 1.0% and the polymer concentration was 0.3%. Moreover, it is found from simulation results that the development of soap/surfactant gradient in ASP flooding ensures the process passing through the optimal condition, where minimum IFT and low residual oil saturation will be attained.
- Asia (0.93)
- North America > United States > Texas (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (0.69)
- Geology > Mineral > Sulfide > Iron Sulfide > Pyrite (0.61)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
General Overview This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode. Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model. The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.
Surfactant Flooding in Offshore Environments
Southwick, J. G. (Shell Global Solutions, N.V.) | Pol, E. van (Shell Global Solutions, N.V.) | Rijn, C. H. (Shell Global Solutions, N.V.) | Batenburg, D. W. (Shell Global Solutions, N.V.) | Manap, Arif Azhan (Group Research and Technology PETRONAS) | Mastan, Ahmad Anis (Group Research and Technology PETRONAS) | Zulkifli, Nazliah Nazma (Group Research and Technology PETRONAS)
Abstract A low complexity chemical flooding formulation has been developed for application in offshore environments. The formulation uses seawater with no additional water treatment beyond that which is normally performed for water flooding (filtration, de-oxygenation, etc.). The formulation is a mixture of an alkyl propoxy sulfate (APS) and an alkyl ethoxy sulfate (AES) with no cosolvent. With seawater only (no salinity gradient) the blend of APS and AES gives substantially higher oil recovery than a blend of APS and internal olefin sulfonate (IOS) in outcrop sandstone. It is shown that the highest oil recovery is obtained with surfactant blends that produce formulations that are underoptimum (Winsor Type 1 phase behavior) with reservoir crude oil. Also, these underoptimum formulations avoid high injection pressures seen with optimum formulations in low permeability outcrop rock. The formulation recovers a similar amount of oil in reservoir rock in the swept zone. Overall recovery in reservoir rock is lower than outcrop sandstone due to greater heterogeneity, which causes bypassing of crude oil.
- Europe (0.94)
- Asia (0.93)
- North America > United States > Oklahoma (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- Geology > Mineral > Sulfate (0.56)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.49)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract This is the final installment in a series of three papers examining iron mineralogy and its effect on surfactant adsorption in reservoir and outcrop rock samples. The goal of these studies is to establish best practices for obtaining surfactant adsorption values representative of those in a reduced oil reservoir, despite performing experiments in an oxidizing laboratory atmosphere. This article follows two others examining the abundance and form of iron in the reservoir and in core samples (Part I: Levitt et al., 2015), and a proposed core restoration technique utilizing iron-reducing bacteria (Part II: Harris et al., 2015). In this Part III, chemical reduction methods are examined. Surfactant retention is a leading uncertainty in economic forecasting of chemical EOR, in large part due to the order-of-magnitude effects of artifacts such as improper core preservation. The industry standard is to (a) limit atmospheric contact of cores to the extent feasible, and (b) when necessary, reduce oxidized cores using strong reducing agents such as sodium dithionite, along with buffering and chelating agents such as sodium bicarbonate and EDTA or sodium citrate. However few studies have been performed to determine whether such invasive treatments are necessary, or what unintended effects the use of such reactive chemicals may have. The most striking conclusion from these studies is the lack of clear evidence of any advantage of electrochemical reduction versus a simpler treatment with chelators such as sodium citrate or EDTA. Wang (1993) suggests that oxidation of reservoir cores leads to higher surfactant adsorption due to the reduction of clays, which yields a more negative surface charge. Static experiments with montmorillonite clay, as well as an oxidized outcrop containing significant clay and iron content, illustrate that rinsing with non-reducing agents such as sodium bicarbonate, EDTA, or sodium citrate can lower adsorption as much as a strong reducing agent such as sodium dithionite. In the case of montmorillonite, cation exchange appears to be the mechanism by which adsorption is lowered, and so NaCl alone is sufficient to lower adsorption to near-zero values. For the iron- and clay-containing outcrop material, initial measurements indicating "adsorption" far in excess of a dense bilayer were due in fact to the precipitation of sulfonate surfactant with calcium, which eluded from the dissolution of small amounts of anhydrite. An alkyl alkoxy sulfonate surfactant showed higher calcium tolerance, and did not yield "multilayer" adsorption when equilibrated with the anhydrite-containing core sample. While treatment with a citrate-bicarbonate-dithionite solution does indeed lower adsorption several-fold further, solutions of either sodium bicarbonate or EDTA are at least as effective, and sodium citrate is almost as effective. These non-reductive treatments remove small amounts (~0.1% โ ~0.2% of rock mass) of Fe and Al, and fines are invariably apparent in treatment fluids, both of which suggest removal of small amounts of trivalent Fe/Al colloids. Wang (1993) suggests reduction or removal of trivalent iron from clay surfaces as a possible mechanism of lowered adsorption under electrochemically reducing conditions. These results suggest that removal of trivalent cations, with concomitant lowering of anionic surfactant adsorption, is possible with non-reductive chelators such as sodium citrate or sodium EDTA. Sodium bicarbonate is equally effective at lowering adsorption, but does not result in elution of Fe or Al, indicating that these are likely reprecipitated. PIPES buffer, which is used in biological applications for its low propensity to form ligands, lowers adsorption as much and no more than a 10% NaCl rinse, suggesting only anhydrite removal and possibly cation exchange with clays occurs. While these results suggest that non-reductive means may be used to remove artifacts introduced by core oxidation, they come with an important caveat: even rinsing with a brine solution can result in significant alteration of mineralogy. The use of chelating agents will invariably result in dissolution of any soluble minerals present such as gypsum or anhydrite, which can be an important contributor to surfactant (in particular ABS) consumption. In cases where iron removal is necessary due to polymer degradation issues, PIPES buffer is proposed for use as an alternative to bicarbonate, the latter having a greater tendency for ligand formation. The combination of borohydride and bisulfite is suggested as an alternative to dithionite as a reducing agent, resulting in more complete iron removal under some conditions, and anecdotally less tendency for polymer degradation upon subsequent oxidation, though both of these claims should be verified.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (Rane and Xu 2015). This indicates surfactant plating out on rock in the near-wellbore (NWB) region, restricting travel deeper into the reservoir, which compromises well performance. This study presents a sacrificial agent (SA) to cover rock surface near the wellbore, allowing surfactant to penetrate the formation. Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications. As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
Adsorption in Chemical Floods with Ammonia as the Alkali
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)
Abstract 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.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
Design of a Robust ASP Formulation for Clay Rich and Moderate Permeability Sandstone Reservoir: From Laboratory to Single Well Chemical Tracer Test in the Field
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. (TIORCO, a Nalco Champion Company)
Abstract 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.
- North America > United States > Wyoming (0.34)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Wind River Basin > NPR-3 > Muddy Formation (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)