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Collaborating Authors
Waterflooding
Abstract It is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs. In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
- Asia > Middle East (0.28)
- North America > United States (0.18)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.52)
- Geology > Mineral > Carbonate Mineral > Calcite (0.49)
Abstract Low salinity waterflooding (LSF) research has been gaining more momentum in recent years for both sandstone and carbonate reservoirs. Published laboratory data and field tests have shown an increase in oil recovery by changing injected brine salinity, especially for sandstone reservoirs. It is widely accepted that low salinity water alters the wettability of the reservoir rock from less to more water-wet conditions, oil is then released from rock surfaces and recovery is increased. The main objectives of the current study are to: test the potential of increasing oil recovery by LSF of a carbonate reservoir and to investigate the factors that control it. The impact of LSF on oil recovery was investigated by conducting coreflood and spontaneous imbibition experiments at 70 °C using core samples from a carbonate reservoir, crude oil and synthetic brine (194,450 ppm) which was mixed with distilled water in four proportions twice, 5 times, 10 times and 100 times dilution brines. Moreover, both crude oil/brine interfacial tension measurements (IFT) and ionic exchange experiments were carried out at room temperature (25 °C). The results of the study show higher oil recovery as a result of reducing injected water salinity in both coreflood and spontaneous imbibition experiments. Coreflood experiments showed an increase in oil recovery by 3 to 5 % of OOIP, while spontaneous imbibition experiments showed an increased by 16 to 21 %. Additionally, spontaneous imbibition experiments provide direct evidence of wettability change by the LSF. The study also shows that the increase in oil recovery was obtained at much higher water salinity than the one observed in the case of sandstone rock.
- Europe (1.00)
- Asia > Middle East (0.94)
- North America > United States > California (0.29)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.96)
- Geology > Mineral (0.95)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
Abstract Evaluation of the scaling risk at production wells is generally carried out using thermodynamic prediction models. These models are generally very accurate in terms of predicting the type of scale that may form, the degree of supersaturation, and the mass of scale that will deposit by the time the system reaches equilibrium – provided the brine composition or compositions involved are well known, and the pressure and temperatures conditions are accurately specified. However, in performing these calculations, engineers and chemists often fail to take account of reactions occurring in the reservoir, and assume that brines reaching the production wells have not reacted in any way prior to entering the wellbore. This often leads to a significant overestimate of the scaling risk. The work presented in this paper addresses this issue by studying data from various fields to identify what can be learnt from the produced brine compositions. A new technique to estimate the range of scaling tendencies that takes account of reservoir precipitation is developed, and the results are displayed in a 3D response surface. This is illustrated for barium sulphate scaling tendency, accounting for different levels of ion stripping. In order to calibrate some simulation parameters, and to identify the more important equations that should be inserted in the reservoir simulation, studies were performed based on the observed data. Different reservoir simulations were used and compared, with a focus on scale management to identify positive and negative aspects of each one. This work has identified that in fields with reservoir temperatures above 120°C and calcium concentrations above 7000 mg/l, significant sulphate stripping occurs due to anhydrite precipitation. This effect is increased where ion exchange leads to a reduction in magnesium and an increase in calcium concentration as the injected brine is displaced through the reservoir.
- Europe > United Kingdom > Scotland (0.28)
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- (3 more...)
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs-Single-Well Surfactant Injection Test
Hsu, Tzu-Ping (University of Oklahoma) | Prapas, Lohateeraparp (University of Oklahoma) | Roberts, Bruce L. (University of Oklahoma) | Wan, Wei (University of Oklahoma) | Lin, Zhixun (University of Oklahoma) | Wang, Xiaoguang (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Ben Shiau, B. J. (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Abstract Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Caand Mg, the presence of iron in the brine can be a challenging issue. Different surfactant formulations incorporating cosurfactants and co-solvents are studied. These formulations minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations are further studied in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at 42°C. Using similar injection protocols, 0.5 PVs surfactant/polymer, oil recoveries ranging from 50 % to 70% of the residual oil (Sor) after waterflooding are observed. The level of surfactant loading is less than 0.6 wt%. A single-well test is conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 165,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of a high-salinity surfactant-polymer formulation composed of 0.23 wt% of surfactant and 1,800 ppm of polymer loading. Approximately 87% of the residual oil was mobilized.
- North America > United States > Pennsylvania (0.34)
- North America > United States > West Virginia (0.24)
- North America > United States > Ohio (0.24)
- North America > United States > Kentucky (0.24)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.51)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Fundamental investigations into wettability and low salinity flooding by parameter isolation
Suijkerbuijk, B. M. (Shell Global Solutions International) | Hofman, J. P. (Shell Global Solutions International) | Ligthelm, D. J. (Shell Global Solutions International) | Romanuka, J.. (Shell Global Solutions International) | Brussee, N.. (Shell Global Solutions International) | van derLinde, H. A. (Shell Global Solutions International) | Marcelis, A. H. (Shell Global Solutions International)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Eighteenth SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 14-18 April 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Improved oil recovery by low salinity waterflooding (LSF) represents an attractive emerging oil recovery technology, as it is relatively easy to implement and low-cost compared to other Improved and Enhanced Oil Recovery (IOR and EOR, respectively) processes. Even though LSF leads to extra oil recovery in most laboratory experiments and some promising data from the field have been presented, the mechanism underlying LSF is still unclear. Therefore it is difficult to predict a favorable performance of LSF in one field a priori, while dismissing others. This paper describes a series of spontaneous imbibition experiments on Berea outcrop core plugs, and some reservoir rock core plugs, that were designed to determine the impact of formation water, imbibing water and crude oil composition on wettability and on wettability modification by LSF. The data presented in this paper lead us to conclude that: - Spontaneous imbibition experiments with formation brine and low salinity brine executed on Berea outcrop material aged with a crude oil show excellent reproducibility; - An increasing concentration of divalent cations in the formation brine makes a Crude Oil/Brine/Rock system more oil-wet; - The extent of wettability modification towards more oil-wet upon aging also depends on the types of cations in the formation brine; - Improved oil recovery by exposure of the aged plugs to NaCl brines occurred when the imbibing phase was either higher or lower in salinity than the formation brine; - Aging of the same brine/rock system with different crudes having diverse physico-chemical properties led to: o A spread in wettabilities after aging o A crude oil-dependent low salinity effect These results are discussed within the context of several mechanisms that have been put forward previously as an explanation for the low salinity effect.
- Europe (1.00)
- Asia (1.00)
- North America > United States > Texas (0.67)
- North America > United States > Oklahoma > Tulsa County > Tulsa (0.24)
- Geology > Geological Subdiscipline (0.67)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (10 more...)
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs
Shiau, B. J. (Prapas, Lohateeraparp) | Hsu, Tzu-Ping (Prapas, Lohateeraparp) | Wan, Wei (University of Oklahoma) | Lin, Zhixun (University of Oklahoma) | Roberts, Bruce L. (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Abstract Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca, Mg, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 0.5 pore volumes of surfactant/polymer + 0.5 pore volumes of polymer drive, experimental results show the oil recovery ranging from 46 % to 89% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 185,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of the high-salinity surfactant-polymer formulation (0.4 wt% of surfactant and 1,800 ppm of polymer loading). The Sor was reduced from 25% to 7% resulting in approximately 72 % of the residual oil being mobilized. A pilot test at the same reservoir is scheduled to be performed in 2012 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
- North America > United States > Pennsylvania (0.34)
- North America > United States > West Virginia (0.24)
- North America > United States > Ohio (0.24)
- North America > United States > Kentucky (0.24)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.66)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)