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Wartenberg, Nicolas (Solvay-The EOR Alliance) | Kerdraon, Margaux (Solvay-The EOR Alliance) | Salaun, Mathieu (Solvay-The EOR Alliance) | Brunet-Errard, Lena (IFPEN-The EOR Alliance) | Fejean, Christophe (IFPEN-The EOR Alliance) | Rousseau, David (IFPEN-The EOR Alliance)
Abstract This paper is dedicated to the selection of the most effective way of mitigating surfactant adsorption in chemical EOR flooding. Mitigation strategies based on either water treatment or adsorption inhibitors were benchmarked for a sea water injection brine, on both performances and economics aspects. Performances in surfactant adsorption reduction were evaluated by applying salinity and/or hardness gradient strategies through dedicated water softening techniques, such as reverse osmosis or nanofiltration. Adsorption inhibitor addition, which does not require any water treatment, was also assessed and optimized for comparison. For each scenario, a suitable surfactant formulation was designed and evaluated through phase diagrams, static adsorption and diphasic coreflood experiments. Then the real benefit of surfactant adsorption reduction on the overall EOR process economics (including the costs of chemicals and water treatment) was assessed depending on the selected strategy. Sea water was considered as the injection brine for this study as it is widely used in chemical EOR process and often suffers high surfactant adsorption level. It was found that residual oil saturation after chemical flooding (SORc) dropped from 29% to 7% by applying a hardness gradient through nanofiltration process while 4% was reached with reverse osmosis. Regarding costs and footprint however, nanofiltration was found to be more advantageous. Adsorption inhibitors addition met similar performances to nanofiltration-based process (SORc=7%) and could be a valuable option depending on injected volume (pilot or small deployment) or field location (off-shore) as they do not require water treatment plant investment. Overall, this study provides useful practical insights on both performances and economics for selecting the most adapted strategy depending on the considered field case.
Abstract Injection Fall-Off (IFO) testing is one of the most important methods to help monitor injector performance over time in waterfloods, water disposal operations, polymer floods, etc. IFO tests provide information about, amongst others, k*h, skin, reservoir transmissibility, and mobility contrasts. Analysis of the early-time period of such tests also can yield estimates of length and height of fractures that are induced during injection. There is however, one important parameter that cannot be estimated from IFO tests, which is the Fracture Closure Pressure (FCP) which is generally considered to be a measure for minimum principal in-situ stress. In this work, we present exact 3D simulations of hydraulic fracture propagation, followed by fracture closure as a result of shut-in and after-closure reservoir flow. The simulations focus on the details of valve closure at the wellhead followed by propagation and (repeated) reflection of the closure-induced pressure pulse (‘water hammer’) whilst at the same time the fracture is gradually closing. The simulated post shut-in pressure decline trends which are the combined result of water hammer, fracture closure and reservoir fluid flow have been compared with field data. The main result that consistently emerged from our simulations and their comparison with field data is that the water hammer disappears as soon as the fracture is completely closed. This can be explained by the fact that the magnitude of a water hammer following injector shut-in strongly increases with the total ‘system’ (wellbore plus fracture) compliance (storage), as is evidenced from our simulations. Since often, the system compliance for an open fracture is an order of magnitude higher than for a closed fracture, fracture closure itself results in a practical disappearance of water hammer. Thus, identification of the point of water hammer disappearance after shut-in allows one to estimate FCP.
Chemical flooding is one of the classical EOR methods, together with thermal methods and gas injection. It is not a new method; indeed, the first polymer flood field pilots date back to the 1950s while the first surfactant-based pilots can be traced back to the 1960s. However, while both gas injection and thermal methods have long been recognised as field proven and are being used at a large scale in multiple fields, it is not the case for chemical EOR.
Although there have been over 500 polymer flood pilots recorded, and almost 100 surfactant-based field tests, large scale field applications are few and far between. This situation seems to be evolving however, as more and more large scale chemical projects get underway. This paper proposes to review the status of chemical EOR worldwide to determine whether it is finally coming of age.
The status of chemical EOR projects worldwide will be reviewed, focusing on recent and current large-scale field developments. This will allow to establish what is working and where the industry is still encountering difficulties. This review will cover North America, South America, Europe, the Middle East, Asia and Africa.
It is clear that polymer flooding is now indeed becoming a well-established process, with many large-scale projects ongoing or in the early stages of implementation in particular in Canada, Argentina, India, Albania and Oman in addition to China. Strangely enough, the US lags behind with no ongoing large-scale polymer flood.
The situation is more complex for surfactant-based processes. At the moment, large-scale projects can only be found in China and – although to a lesser extent – in Canada. The situation appears on the brink of changing however, with some large developments in the early stages in Oman, India and Russia. Still, the economics of surfactant-based processes are still challenging and there is some disagreement between the various actors as to whether surfactant-polymer or alkali-surfactant polymer is the way to go.
This review will demonstrate that polymer flooding is now a mature technology that has finally made it to very large-scale field applications. Surfactant-based processes however, are lagging behind due in part to technical issues but even more to challenging economics. Still there is light at the end of the tunnel and the coming years may well be a turning point for this technology.
Ye, Zheng (Baker Hughes) | Forsberg, Michael (Baker Hughes) | Rutter, Risa (Baker Hughes) | Smith, Spencer (Baker Hughes) | Najmi, Kamyar (Baker Hughes) | Lack, Ryan (Baker Hughes) | Hoines, Jason (Baker Hughes) | Gunter, Shawn (Baker Hughes)
Affinity law teaches that when the rotating speed of the electric submersible pump (ESP) pump is tripled, the flow rate triples and the head increases to nine times the original pump. Thus, a high-speed ESP has the potential of delivering increased production at deeper setting depths and opportunity for shorter equipment allowing operators to land the equipment in shorter tangent sections. Operation at high-speed also presents additional challenges with one of the most significant being increased potential for abrasive and erosive wear. This study compares pump performance from slurry testing to help evaluate the potential trade-offs system performance versus wear when operating at higher speeds.
When deploying ESPs in sandy applications, sand particles can enter the seal clearance between impeller and diffuser creating 3-body abrasion wear. Meanwhile, the 2-body erosion wear in stage flow path reshapes the hydraulic geometry and causes additional losses. Both abrasion and erosion cause pump head reduction, efficiency deterioration, and thrust increase. Data was collected during slurry testing for comparison of performance over the test period. The in situ head change and thrust change were monitored during the slurry test. Pre and posttest stage dimensional data were gathered for comparison. Sand samples were gathered and analyzed to ensure similar slurry conditions applied to all the tested pumps.
Slurry testing and analysis for the evaluation of ESP pump stage performance deterioration for a stage operated at 10,000 RPM as compared to a stage operated at 3,500 RPM will be provided. The pump performance degradation and dimensional wear were compared. This demonstrates higher speed ESP pump components can be created that show similar abrasive wear performance to current ESP pump.
A 10,000 rpm ESP pump completed slurry testing while measuring pressure, temperature, flow and thrust. The results provide pump performance deterioration trend in a sand application and helps to understand physics of stage wear mechanism. This is the first of this type of testing apparatus to authors’ knowledge. It also serves as a backbone in high-speed pump validation program.
Vitthal, Sanjay (Shell Exploration & Production Co) | Chapylgin, Dmitry (Salym Petroleum Development) | Liu, Xin (Shell International Exploration and Production) | Khamadaliev, Damir (Salym Petroleum Development) | Fair, Phillip (Shell International Exploration and Production)
During hydraulic fracturing of low to moderate (0.1 – 50 md) permeability reservoirs using crosslinked gel fluids, the final proppant stage displacement is designed to leave some volume of proppant slurry above the perforated interval. This practice of underflushing is based on a paradigm that considers the overdisplacement of proppant past perforations to be a major risk to well productivity. The theory behind this paradigm is investigated and finds that it relies on several physically unrealistic assumptions. Numerical simulations were performed to understand the impact of a fracture overflush on well productivity. A new methodology was developed for overflushing fractures that enables significant cost/time savings without impacting well productivity. A multi-well field trial in a 2-20 md reservoir was conducted andcompared well performance from overflushed crosslinked gel fractures to underflushed fractures. Some of the trial results have been reported by the authors (
Dean, Elio (Surtek, Inc.) | Pitts, Malcolm (Surtek, Inc.) | Wyatt, Kon (Surtek, Inc.) | James, Dean (Surtek, Inc.) | Mills, Kathryn (Surtek, Inc.) | Al-Murayri, Mohammed (KOC) | Al-Kharji, Anfal (KOC)
With a resurgence of chemical EOR opportunities throughout the world, high concentration surfactant design has re-emerged its uneconomic face. High concentration surfactant formulation is the micellar polymer design from the past that produced high oil recoveries in the lab but were uneconomic in the field. Formulation designs must consider factors beyond simply oil recovery for economic success and to minimize production issues in the field.
Analysis and comparison of micellar polymer design projects from the 1970-1980s to current SP/ASP formulation designs are discussed. A simple formulation cost calculator is showcased, costs of all formulations are presented, and price per incremental barrel produced (chemical cost only) are shown assuming a 0.1 PV of incremental recovery.
Analysis concludes the following:
Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion. Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects. Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil. Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success.
Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion.
Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects.
Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil.
Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success.
The industry is taking steps back to an uneconomic time of chemical EOR by obscuring the difference between designs meant to increase reserves (economic oil) versus those that serve an academic or research purpose. Operators are unwittingly paying the price to advance the science of chemical EOR when service companies provide formulations that are not economic. This paper is meant to remind the industry that high concentration surfactant formulations never were economic and certainly will not be economic in today's price environment.
Al-Saedi, Hasan N. (Missouri University of Science and Technology/Missan Oil Company) | Flori, Ralph E. (Missouri University of Science and Technology) | Al-Jaberi, Soura K. (Missan Oil Company) | Al-Bazzaz, Waleed (Kuwait Institute for Scientific Research)
Summary Generally, injecting carbon dioxide (CO2) into oil reservoirs is an effective enhanced oil recovery (EOR) technique that improves oil recovery, but injecting CO2 alone can be compromised by problems, such as early breakthrough, viscous fingering, and gravity override. The base CO2 injection method was improved by water-alternating-gas (WAG) injection with formation water (FW) and with low-salinity (LS) water (LSW), with LSW WAG achieving greater recovery than WAG with FW. This study investigates various combinations of standard waterflooding (with FW); flooding with nonmiscible gaseous CO2; WAG with CO2 and FW and/or LSW; foam flooding by adding a surfactant with CO2; adding an alkaline treatment step; and finally adding an LSW spacer between the alkaline step and the foam. These various EOR combinations were tested on Bartlesville sandstone cores (ϕ of approximately12%, K of approximately 20 md) saturated with a heavy oil diluted slightly with 10% heptane for workability. The ultimate outcome from this work is a “recipe” of EOR methods in combination that uses alkaline, LSW, surfactant, and CO2 steps to achieve recovery of more than 63% of the oil originally in place (OOIP) in coreflooding tests. Combining CO2 injection with surfactant [sodium dodecyl sulfonate (SDS)] to produce a foam resulted in better recovery than the WAG methods. Adding alkaline as a leading step appeared to precipitate the surfactant and lower recovery somewhat. Adding an LSW spacer between the alkaline treatment and the foam resulted in a dramatic increase in recovery. The various cases of alkaline + LSW spacer + surfactant + CO2 (each with various concentrations of alkaline and surfactant) achieved an average improvement of 7.71% of OOIP over the identical case(s) without the LSW spacer. The synergistic effect of the LSW spacer was remarkable. ERRATUM NOTICE:An erratum has been added to this paper detailing addition of an omitted reference.
Summary Recent investigations have shown that treatment with injected brine composition can improve oil production. Various mechanisms have been suggested to go through the phenomenon; nevertheless, wettability alteration is one of the most commonly proposed mechanisms in the literature. Wettability alteration of the porous media toward a more favorable state reduces the capillary pressure, consequently contributing to the oil detachment from pore walls. In this study, phase behavior, oil recovery, and wettability alteration toward a more favorable state were investigated using a combination of formulations of surfactant and modified low-salinity (LS) brine. Phase behaviors of these various formulations were examined experimentally through observations on relative phase volumes. Experiments were performed in various water/oil ratios (WORs) in the presence of two different oil samples, namely C1 and C2. These experiments were conducted to clarify the impact of each affecting parameter; in particular, the impact of resin and asphaltene of crude oil on the performance of LS surfactant (LSS) flooding. Hereafter, the optimal formulation was flooded into the oil-wet micromodel. Optimum formulations increased the capillary number more than four orders of magnitude higher than that under formation brine (FB) flooding, thus causing oil recovery rates of 61 and 67% for oil samples C1 and C2, respectively. Likewise, the wettability alteration potential of optimized formulations was studied through contact angle measurements. Results showed that LS and LSS solutions could act as possible wettability alternating methods for oil-wet carbonate rocks. Using the optimum formulation resulted in a wettability alteration index (WAI) of 0.66 for sample C1 and 0.49 for sample C2, while using LS brine itself ended in 0.51 and 0.29 for oil samples C1 and C2, respectively. Introduction With increasing energy demand, the need to increase the oil recovery from reservoirs is felt more than ever. Unfortunately, more than two-thirds of oil remains in the reservoir after the primary and secondary stages of production. Therefore, an enhancement in oil recovery can be accomplished through better engineering and project management (Alvarado 2010; Sheng 2010; Lake et al. 2014; Dantas et al. 2019; Sharma et al. 2019). Capillary forces trap the oil droplets in the pore space and cause a high degree of curvature between the oil and water interface.
Al Kalbani, Munther Mohammed (Heriot-Watt University) | Jordan, Myles Martin (Champion X) | Mackay, Eric James (Heriot-Watt University) | Sorbie, Ken Stuart (Heriot-Watt University) | Nghiem, Long X. (Computer Modelling Group Ltd.)
Abstract Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca, Mg, HCO3) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)2 scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.
Schumi, Bettina (OMV E&P) | Clemens, Torsten (OMV E&P) | Wegner, Jonas (HOT Microfluidics) | Ganzer, Leonhard (Clausthal University of Technology) | Kaiser, Anton (Clariant) | Hincapie, Rafael E. (OMV E&P) | Leitenmüller, Verena (University of Leoben)
Summary Chemical enhanced oil recovery (EOR) leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high total acid number (TAN) could be produced by the injection of alkali. Alkali might lead to the generation of soaps and emulsify the oil. However, the generated emulsions are not always stable. Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. On the basis of the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in the formation of initial emulsions is observed. Micromodel experiments are performed to investigate the effects on the pore scale. For the injection of alkali into high‐TAN oils, the mobilization of residual oil after waterflooding is seen. The oil mobilization results from the breaking up of oil ganglia or the movement of elongated ganglia through the porous medium. As the oil is depleting in surface‐active components, residual oil saturation is left behind either as isolated ganglia or in the down gradient side of grains. Simultaneous injection of alkali and polymers leads to a higher incremental oil production in the micromodels owing to larger pressure drops over the oil ganglia and more‐effective mobilization accordingly. Coreflood tests confirm the micromodel experiments, and additional data are derived from these tests. Alkali/cosolvent/polymer (ACP) injection leads to the highest incremental oil recovery of the chemical agents, which is difficult to differentiate in micromodel experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micromodels, the incremental oil recovery is also higher for alkali/polymer (AP) injection than with alkali injection only. To evaluate the incremental operating costs of the chemical agents, equivalent utility factors (EqUFs) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and, hence, the lowest chemical incremental operating expenditures are incurred by the injection of Na2CO3; however, the highest incremental recovery factor is seen with ACP injection. It should be noted that the incremental oil recovery owing to macroscopic‐sweep‐efficiency improvement by the polymer needs to be accounted for to assess the efficiency of the chemical agents.