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Gospodarev, Dmitry (R&D Institute BelNIPIneft, Belorusneft) | Lymar, Igor (R&D Institute BelNIPIneft, Belorusneft) | Rakutko, Aleksandra (R&D Institute BelNIPIneft, Belorusneft) | Antuseva, Anastasia (R&D Institute BelNIPIneft, Belorusneft) | Tkachev, Dmitry (R&D Institute BelNIPIneft, Belorusneft)
Abstract Nowadays, chemical EOR methods are becoming more and more relevant, among which the alkali-surfactant-polymer flooding is of particular interest. The efficiency of this technology largely depends on the correct choice of the components of chemical formulation, which should be based on a set of laboratory experiments carried out in a given sequence. This paper presents a methodological approach to laboratory studies in order to develop an optimal surfactant-polymer formulation, taking into account the geological and physical characteristics of the target field and the properties of reservoir fluids. The experimental part of the research work was carried out in several stages, involving the analysis of the physicochemical characteristics of reservoir oil, the screening studies of surfactant and polymer samples, as well as a series of coreflood tests with a selected chemical formulation on the terrigenous reservoir models. During screening studies, the solubility and compatibility of the chemical components, the phase behavior of surfactant solutions with oil at different salinity values and water-oil ratios, static adsorption of chemicals on the rock and their thermal stability at reservoir temperature were investigated. Optimization of the chemical formulation was based on the results of IFT measurements of the surfactant solutions and rheological studies of the polymer solutions. At the stage of coreflood tests, physical simulation of the surfactant-polymer flooding was carried out on reservoir models using natural core material in order to optimize the composition and slug size of the developed chemical formulation. The obtained results of the displacement experiment were matched by numerical 1D simulation. Based on the results of the studies performed, an effective surfactant-polymer formulation has been designed, which provides the ultra-low IFT (2.8·10 mN/m) values and the ability to form stable middle-phase microemulsions when interacting with oil. The findings of thermal stability and static adsorption experiments confirmed a feasibility of selected chemicals for practical application. Within the framework of the study, the key technical parameters of proposed formulation were determined, which are required for up-scaled simulation study of the chemical flooding process at pilot site.
Abstract This paper presents the results of an ongoing rental project at Slavneft (a company belonging on a parity basis to Gazpromneft and Rosneft) within 13 Licence Areas. The main target of Ultra-High-Speed ESP implementation was to address challenges where traditional technologies become inefficient, with the main priority given to production gain. The paper scope is focused on how production gain and power savings were achieved. Ultra-High-Speed ESP (UHS ESP) Systems have grown in popularity in recent years due to a set of advantages, including power efficiency, wide operating range, robust design, etc. Once the technology reached a level where equipment runlife became superior to standard ESPs (STD ESP), it opened new prospects for exploring various types of business models with lease being one of them. Project scope at Slavneft group of field required solutions for depleting reservoirs in slim casing (5.5" and 5.75"). Since production gain was given high priority, deeper ESP installation was required. Target KPI's uncovered the benefit of short UHS downhole string length, which allows for deeper installation, where dogleg severity becomes critical and traditional ESP cannot be set. Preliminary results of a three-year project with one-year qualification are as follows: Net production gain of 13,846 tons of oil (103,200 stb) achieved through deeper installation, average daily production gain 23.9 %; Flowing bottom hole pressure reduced by 11.8 bar (24.6 %) on average; UHS ESPs installed deeper by average 252 m (827 ft) than previously installed standard ESP; Average specific power consumption optimized by 6.1 kW*h/m3 (liquid) or 23.5 %; Total power saved is over 1,685,553 kW*h. This case study touches on broader aspects of the rental project, demonstrating specific topics within the area of UHS ESP application. As technology benefits become more apparent and they offer tremendous opportunities for production optimization, with time, the UHS ESP may completely replace standard approach. The results of this study and a number of other successful projects all over the world have paved the way for a more advanced approach in Artificial Lift. Taking a step forward towards unlocking potential of every well, the final chapter of this paper presents the results of a 7-year long project, aimed at bringing to life a Hyper Speed ESP system, with its speed rating reaching 15,000 rpm. The Hyper Speed ESP designed to provide ultimate solution for ESP lifted wells: Ready for practically any downhole conditions Benchmark reliability & efficiency Rigless live-well deployment Inexpensive intervention, compact & slim Paper scope covers technological hurdles and corresponding engineering solutions.
Sotomayor, Mauricio (The University of Texas at Austin) | Alshaer, Hassan (The University of Texas at Austin) | Chen, Xiongyu (The University of Texas at Austin) | Panthi, Krishna (The University of Texas at Austin) | Balhoff, Matthew (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
Abstract Harsh conditions, such as high temperature (>100 oC) and high salinity (>50,000 ppm TDS), can make the application of chemical enhanced oil recovery (EOR) challenging by causing many surfactants and polymers to degrade. Carbonate reservoirs also tend to have higher concentrations of divalent cations as well as positive surface charges that contribute to chemical degradation and surfactant adsorption. The objective of this work is to develop a surfactant-polymer (SP) formulation that can be injected with available hard brine, achieve ultra-low IFT in these harsh conditions, and yield low surfactant retention. Phase behavior experiments were performed to identify effective SP formulations. A combination of anionic and zwitterionic surfactants, cosolvents, brine, and oil was implemented in these tests. High molecular weight polymer was used in conjunction with the surfactant to provide a high viscosity and stable displacement during the chemical flood. Effective surfactant formulations were determined and five chemical floods were performed to test the oil recovery potential. The first two floods were performed using sandpacks from ground Indiana limestone while the other three floods used Indiana limestone cores. The sandpack experiments showed high oil recovery proving the effectiveness of the formulations, but the oil recovery was lower in the cores due to complex pore structure. The surfactant retention was high in the sandpacks, but it was lower in Indiana Limestone cores (0.29-0.39 mg/gm of rock). About 0.4 PV of surfactant slug was enough to achieve the oil recovery. A preflush of sodium polyacrylate improved the oil recovery.
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.
Abstract 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.
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)
Abstract 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 (Chaplygin et. al. (2019)) and are further updated/analyzed in this work. The analysis confirmed that the managed overflush fractures have equivalent performance to underflushed fractures. The analysis also confirmed multiple benefits from the managed overflush wells including reductions in completion costs/time and an improved HSSE risk profile. The results challenge the validity of this decades old paradigm.
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)
Abstract 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. 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.