Design of in-Depth Conformance Gel Treatment to De-Risk ASP Flooding in a Major Carbonate Reservoir

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim A. Hassan ◽  
Deema Alrukaibi ◽  
Amna Al-Qenae ◽  
Jimmy Nesbit ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Significant Risk ◽  
High Viscosity ◽  
Carbonate Reservoir ◽  
High Permeability ◽  
Laboratory Design ◽  
Gel Treatment ◽  
Viscosity Polymer ◽  
Chromium Acetate

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor sweep efficiency, both areal and microscopic. An Alkaline-Surfactant-Polymer (ASP) pilot is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Design of the gel conformance treatment was multi-faceted. Rapid breakthrough of tracers at the pilot producer from each of the individual injectors, less than 3 days, implied a direct connection from the injectors to the producer and poses significant risk to the success of the pilot. A dynamic model of the SAMA pilot was used to estimate in the potential injection of either a high viscous polymer solution (~200 cp) or a gel conformance treatment to improve contact efficiency, diverting injected fluid into oil saturated reservoir matrix. High viscosity polymer injection scenarios were simulated in the extracted subsector model and showed little to no effect on diverting fluids from the high permeability streak into the matrix. Gel conformance treatment, however, provides benefit to the SAMA pilot with important limitations. Gel treatment diverts injected fluid from the high permeability zone into lower permeability, higher oil saturated reservoir. After a gel treatment, the ASP increases the oil cut from 3% to 75% while increasing the cumulative oil recovery by more than 50 MSTB oil over ASP following a high viscosity polymer slug alone. Laboratory design of the gel conformance system for the SAMA ASP pilot involved blending of two polymer types (AN 125SH, an ATBS type polymer, and P320 VLM and P330, synthetic copolymers) and two crosslinkers (chromium acetate and X1050, an organic crosslinker). Bulk testing with the polymer-crosslinker combinations indicated that SAMA reservoir brine resulted in not gel system that would work in the SAMA reservoir, resulting in the recommendation of using 2% KCl in treated water for gel formulation. AN 125 SH with S1050 produce good gels but with short gelation times and AS 125 SH with chromium acetate developed low gels consistency in both waters. P330 and P320 VLM gave good gels with slow gelation times with X1050 crosslinker in 2% KCl. Corefloods with the P330-X 1050 showed good injectivity and ultimately a reduction of permeability of about 200-fold. A P330-X 1050 was recommended for numerical simulation studies. Numerical simulator was calibrated by matching bulk gel viscosity increases and coreflood permeability changes. Numerical simulation indicated two of the four injection wells (SA-0557 and SA-0559) injection profile will change compared to water. Overall injection rate was reduced by the conformance treatment and was the corresponding oil rate. Total oil production from the center pilot production well (SA-0560) decreased with gel treatment but ultimately increased to greater rates

Field Implementation of In-Depth Conformance Gel Treatment Prior to Starting an ASP Flooding Pilot

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim Hassan ◽  
Naser Alajmi ◽  
Jimmy Nesbit ◽  
Bastien Thery ◽  
...  
Keyword(s):  
Polymer Solution ◽  
Injection Pressure ◽  
High Viscosity ◽  
Production Well ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
Appreciable Change ◽  
Well Pattern ◽  
Gel Treatment ◽  
Viscosity Polymer

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.

Mitigating Water Production from High Viscosity Oil Wells in Unconsolidated Sandstone Formations

2021 ◽  
Author(s):  
Hamad AL-Rashidi ◽  
Mahmoud Reda Aly Hussein Hussein ◽  
Abdulaziz Erhamah ◽  
Satinder Malik ◽  
Abdulrahman AL-Hajri ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Production Efficiency ◽  
Marked Change ◽  
High Viscosity ◽  
Water Production ◽  
High Permeability ◽  
Improved Oil Recovery ◽  
Lower Permeability ◽  
Water Cut

Abstract Large reserves of High-Viscous Oil in Kuwait calls for Improved Oil Recovery scenarios. In Kuwait unconsolidated sandstone formations, the sandstone intervals represent extensive reservoir intervals of sand separated by laterally extensive non-reservoir intervals that comprise finer-grained, argillaceous sands, silts and muds. The reservoir is shallow with high permeability (above 1000 mD) and under bottom aquifer pressure support. Due to strong viscosity contrast between oil and water, after breakthrough, the water cut rises quickly resulting in strong loss of production efficiency. Mitigating water production is thus mandatory to improve production conditions. The candidate wells have 2 to 3 open intervals in different rock facies with comingle production. The total perforated length is between 38 and 48 ft. Production is through PCP at a rate of around 300 bpd and BS&W is between 71 and 87%. The technology applied utilizes pre-gelled size-controlled product (SMG Microgels) having RPM properties, i.e. inducing a strong drop of relative permeability to water without affecting oil relative permeability. The size is chosen to selectively treat the high-permeability water producing zones while preserving the lower-permeability oil zones. The chemical can also withstand downhole harsh conditions such as salinity of around 170,000ppm and presence of 2% H2S. The treatment consisted of bullhead injection of 300 bbls of pre-gelled chemical through tubing. The first results seem very favourable, sincefor two wells, the water cut has dropped from 80 to 40% with almost same gross production rate. The incremental oil is more than 100 bopd. The third well did not show marked change after WSO treatment. The wells are under continuous monitoring to assess long-term performance. Such result, if confirmed, may lead to high possibilities for the improvement of heavy-oil reservoir production under aquifer support by mitigating water production with simple chemical bullhead injection.

scholarly journals The impact of permeability heterogeneity on water-alternating-gas displacement in highly stratified heterogeneous reservoirs

2021 ◽  
Author(s):  
Mohammad Yunus Khan ◽  
Ajay Mandal
Keyword(s):  
Oil Recovery ◽  
Field Application ◽  
Carbonate Reservoir ◽  
High Permeability ◽  
Oil Saturation ◽  
Heterogeneous Reservoirs ◽  
Heterogeneous Reservoir ◽  
Low Viscosity ◽  
Water Alternating Gas ◽  
The Impact

AbstractAvailability of gases at the field level makes attractive to water-alternating-gas (WAG) process for low viscosity and light oils carbonate reservoir. However, impact of reservoir heterogeneity on WAG performance is crucial before field application. In general, ramp carbonates have heterogeneity due to variation of permeability and porosity. However, WAG performance significantly affected by permeability variations. This article investigates merits and demerits of WAG displacement due to permeability heterogeneities such as permeability anisotropy, high permeability streaks (HKS), matrix permeability, dolomite and thin dense stylolite layers. High-resolution compositional simulations with tuned equation of state (EoS) were carried out using 2D and 3D sector models. The study focuses on WAG performance in terms of oil recovery, vertical sweep, solvent utilization, gas oil ratio (GOR), water cut (WCT), WAG response time, gravity override, hysteresis, un-contacted oil saturation and economics. The results of simulation show that the heterogeneous reservoir provides initially faster WAG response, lower expected ultimate recovery (EUR), faster gas breakthrough, higher GOR and WCT production compared to homogeneous reservoir. The gas gravity override at smaller wells spacing is less in homogeneous reservoir as compared to heterogeneous reservoir, but it is reverse in case of larger well spacing. In heterogeneous reservoir, the HKS shows significant gas override resulting in poor vertical sweep due to capillary holding, and the high permeability dolomite layer shows early water breakthrough. This reservoir has higher solvent utilization in initial stage, and then, it becomes nearly equal to homogeneous reservoir. Simulation in both reservoirs overestimates incremental recovery of 2–3% OOIP at one pore volume injection because of not involving un-contacted oil saturation as predicted in core flood. The findings of this study will help to understand WAG performance and design in highly heterogeneous reservoirs for field applications. Graphical abstract

scholarly journals Evaluation of Polymer Alternating Waterflooding in Multilayered Heterogeneous Waterflooded Reservoir

2018 ◽  
Vol 171 ◽  
pp. 04001
Author(s):  
Warut Tuncharoen ◽  
Falan Srisuriyachai
Keyword(s):  
Numerical Simulation ◽  
Viscous Fluid ◽  
Polymer Solution ◽  
Oil Recovery ◽  
High Viscosity ◽  
Polymer Flooding ◽  
Operating Parameters ◽  
Sweep Efficiency ◽  
Polymer Injection ◽  
Water Breakthrough

Polymer flooding is widely implemented to improve oil recovery since polymer can increase sweep efficiency and smoothen heterogeneous reservoir profile. However, polymer solution is somewhat difficult to be injected due to high viscosity and thus, water slug is recommended to be injected before and during polymer injection in order to increase an ease of injecting this viscous fluid into the wellbore. In this study, numerical simulation is performed to determine the most appropriate operating parameters to maximize oil recovery. The results show that pre-flushed water should be injected until water breakthrough while alternating water slug size should be as low as 5% of polymer slug size. Concentration for each polymer slugs should be kept constant and recommended number of alternative cycles is 2. Combining these operating parameters altogether contributes to oil recovery of 53.69% whereas single-slug polymer flooding provides only 53.04% which is equivalent to 8,000 STB of oil gain.

Numerical Simulation of Combined Reverse Combustion and Steamflooding for Oil Recovery in a Utah Tar Sand

1985 ◽  
Vol 25 (02) ◽  
pp. 227-234 ◽  
Author(s):  
Gbolahan O. Lasaki ◽  
Richard Martel ◽  
John L. Fahy
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Field Tests ◽  
Steam Injection ◽  
High Permeability ◽  
Oil Viscosity ◽  
Good Communication ◽  
Original Oil In Place ◽  
The U.S

Abstract This paper presents the design of the U.S. DOE Laramie Energy Technology Center's (LETC) Project TS-4, which involves numerical simulation of both in-situ reverse combustion and steamflooding. The simulator showed that the combustion could be limited and contained in a middle 10-ft [3-m] interval with a correlatable High-permeability streak within the 65-ft [20-m] pay zone of the upper Rimrock tar sand formation in Northwest Asphalt Ridge, Uintah County, UT. A high-transmissibility path was necessary to obtain adequate injectivity and sustain a stable reverse combustion. Combustion "echoes" developed and the front changed into a forward mode as the formation pressure increased and at very low air-injection rates. Oil recovery by steam injection was accelerated in a formation preheated by a reverse combustion. Introduction In 1973 LETC began a series of projects aimed at identifying feasible oil recovery techniques for the large deposits of tar sands in the U.S. Two previous combustion experiments have been reported by LETC: Land et al previous combustion experiments have been reported by LETC: Land et al reported the LETC TS-1C, and Johnson et al reported the LETC TS-2C. Both of these were conducted in the Northwest Asphalt Ridge tar sand deposit (T4S-R20E), in Uintah County, in 1975 and 1977, respectively. These were followed by a steamflood experiment, LETC TS-1S, in 1980 in the same area. Analysis of this steamflood experiment indicated that only 18.5% of the original oil in place (OOIP) was mobilized because of poor communication between the injector and the producers. It was clear at this point that the producers had to be stimulated to improve the oil mobility around the wellbores. Steam soaking was considered but discarded because of the lack of adequate reservoir pressure. Since LETC had been successful with its previous use of combustion, the use of reverse combustion to preheat the previous use of combustion, the use of reverse combustion to preheat the producers and possibly the entire sand was considered. A reverse producers and possibly the entire sand was considered. A reverse combustion is preferred to forward combustion because it eliminates the problem of plugging. Project TS-4, therefore, involves a combination of problem of plugging. Project TS-4, therefore, involves a combination of in-situ reverse combustion and steamflooding. The site selected for the test is about 200 ft [61 m] southeast of the location of the LETC TS-1S experiment. The project targets the 65-ft [20-m] pay zone of the upper Rimrock tar sand formation rather than the lower Rimrock targeted in all previous experiments. The sand is well confined and fairly continuous with previous experiments. The sand is well confined and fairly continuous with varying levels of shaliness. The formation bitumen saturation is about 80% compared with 35 to 65% in the lower Rimrock. The permeability of the unextracted core is less than 1 md in some parts and generally one or two orders of magnitude less than that of the lower Rimrock. Preliminary field tests ordinarily showed very poor injectivity without fracturing the formation. The in-situ reverse combustion is intended to preheat the formation rapidly before steamflooding the entire formation. It is confined to a 10ft [3-m] interval that includes a correlatable high-permeability streak to limit the air requirement. It also is expected that good communication can be established between the injector and producers while reducing the oil viscosity and, thus, improving the mobility of the oil. This paper reports a simulation study evaluating the feasibility of this project on a commercial scale and presents a conceptual study of the experiment using a numerical simulator previously described by Coats. Owing to the recent defederalization of LETC, the planned field test for Project TS-4 now has been abandoned. Geology The Northwest Asphalt Ridge is located at T4S-R20E in the Uintah Basin, Uintah County, UT. The geology of this area is described in a greater detail by Campbell and Ritzma. The ridge is separated from the major Asphalt Ridge by a northeast-trending fault. The strata dip southwesterly from about 9 to 350 Average dip angle at the TS-4 location is about 28. The Rimrock sandstone is a member of the Late Cretaceous Mesaverde formation. The other member of the group in this location is the Asphalt Ridge sandstone. Both are of marine origin and oil impregnated. The Rimrock sandstone is unconformably overlain by Tertiary Duchesne River formation of continental origin. It is underlain by the Asphalt Ridge sandstone and separated from it by a thin tongue of Mancos shale. SPEJ p. 227

The Experiment of Viscosity Loss Caused by the Polymer Flow along Transportation Pipeline

2015 ◽  
Vol 733 ◽  
pp. 59-62
Author(s):  
Yue Wang ◽  
Guang Sheng Cao ◽  
Gui Long Wang ◽  
Sheng Kun Sun ◽  
Xin Li
Keyword(s):  
Polymer Solution ◽  
Oil Recovery ◽  
High Viscosity ◽  
Shear Effect ◽  
Solution Flow ◽  
Polymer Flow ◽  
The Core ◽  
Flow Through ◽  
Enhance Oil Recovery ◽  
Viscosity Polymer

By using polymer solution with high viscosity, polymer flooding can enhance oil recovery by reducing the mobility ratio of displacing fluid and oil in formation. Therefore, the core of polymer flooding's ground transportation is to keep the viscosity of polymer solution unchanged. According to the process layout of polymer ground transportation, the experimental device was designed and manufactured to determine viscosity loss of pipelines and elbow. We obtained the viscosity loss variation law of the polymer solutions of different concentrations at different flow velocities when they flow through the pipeline and elbow. The experimental results showed that the viscosity of polymer solution will decrease after the polymer solution flow through pipelines and elbow, due to the shear effect. The higher the velocity, the more significant the viscosity loss.

scholarly journals Study on the regional characteristics during foam flooding by population balance model

2020 ◽  
pp. 014459872098361
Author(s):  
Zhongbao Wu ◽  
Qingjun Du ◽  
Bei Wei ◽  
Jian Hou
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Population Balance ◽  
Growth Zone ◽  
Balance Model ◽  
Population Balance Model ◽  
Liquid Ratio ◽  
One Dimensional ◽  
Foam Flooding

Foam flooding is an effective method for enhancing oil recovery in high water-cut reservoirs and unconventional reservoirs. It is a dynamic process that includes foam generation and coalescence when foam flows through porous media. In this study, a foam flooding simulation model was established based on the population balance model. The stabilizing effect of the polymer and the coalescence characteristics when foam encounters oil were considered. The numerical simulation model was fitted and verified through a one-dimensional displacement experiment. The pressure difference across the sand pack in single foam flooding and polymer-enhanced foam flooding both agree well with the simulation results. Based on the numerical simulation, the foam distribution characteristics in different cases were studied. The results show that there are three zones during foam flooding: the foam growth zone, stable zone, and decay zone. These characteristics are mainly influenced by the adsorption of surfactant, the gas–liquid ratio, the injection rate, and the injection scheme. The oil recovery of polymer-enhanced foam flooding is estimated to be 5.85% more than that of single foam flooding. Moreover, the growth zone and decay zone in three dimensions are considerably wider than in the one-dimensional model. In addition, the slug volume influences the oil recovery the most in the foam enhanced foam flooding, followed by the oil viscosity and gas-liquid ratio. The established model can describe the dynamic change process of foam, and can thus track the foam distribution underground and aid in optimization of the injection strategies during foam flooding.

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