bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cyclic Gas Injection EOR Pilot in Tight Viking Sand Pool
Authors: Xie Jin , Neima Andrew 
Published: April 2024

Abstract
The primary goal of this project was to prove the feasibility of a Cyclic Gas Injection/Production (Huff & Puff) enhanced oil recovery (EOR) scheme and evaluate its economic viability in the Viking formation in Saskatchewan, Canada. Historically, the Viking formation has challenging waterflood economics due to limited injectivity into the tight sand reservoir and formation damage caused by movable and swelling clays. The objectives were to test horizontal well injectivity at desired pressures, assess the use of produced gas injection to repressurize the extremely depleted Viking reservoir, evaluate enhanced oil recovery with various inter-well spacings, and to optimize injection and production cycle lengths.
This pilot was designed by utilizing analytical evaluation and numerical simulation. The Huff & Puff pilot consists of four 0.7 mile (1100 m) horizontal wells with two different inter-well spacings; 667 ft vs 1333 ft (200 m vs 400 m). The pilot consisted of two parallel horizontal well pairs, which were designed to alternate injection and production cycles. A detailed reservoir surveillance program was implemented to collect extensive data, including reservoir and wellhead pressures, gas composition analysis, production and injection rates of the pilot wells, and the production rates of surrounding wells to evaluate reservoir response and pilot performance.
Whitecap has been operating this pilot project since its initiation in September 2021 with technical success. Six Huff & Puff cycles with varying durations, between one to three months on injection, have been completed without major operating issues. Per-well injectivity has reached higher than designed 750 Mscf/d (21 e3m3/d) at desired surface pressures. Through the course of six injection cycles, average reservoir pressure has increased from an initial 174-319 psi (1.2-2.2 MPa) to 623-885 psi (4.3-6.1 MPa). The incremental oil recovery factor for the pilot area is expected to be 1%, which is considerable for a reservoir with typical primary recovery factors expected to be only 6-8%. The gas injection has resulted in production increases in some offset wells, and a higher degree of gas breakthrough has been observed in the section with 667 ft (200 m) well spacing. The 3-month injection cycle has resulted in the largest incremental recovery and cycle time optimization efforts are ongoing. The pilot results are encouraging, indicating that a cyclic gas injection EOR scheme could have potential for further commercial expansion.
The pilot has demonstrated Huff & Puff's potential economic viability as an EOR scheme for the tight Viking sand formation, which is one of the most prominent producing formations with low oil recovery factors in the Western Canadian Sedimentary Basin (WCSB). There is no such published pilot information available before. Detailed pilot design, production performance evaluation and learnings are presented in this paper.
Lessons Learned from Laboratory Study and Field Application of Re-Crosslinkable Preformed Particle Gels RPPG for Conformance Control in Mature Oilfields with Conduits/Fractures/Fracture-Like Channels
Authors: Bai Baojun , Schuman Thomas , Smith David , Song Tao 
Published: April 2024

Abstract
This paper surveys the role of re-crosslinkable preformed particle gels (RPPG) in addressing conformance challenges within mature oilfields. Despite widespread preformed particle gel (PPG) application in 15,000+ wells, their limitations in sealing fractures and conduits prevalent in mature reservoirs have driven the development of RPPG formulations. Synthesized in various sizes from micrometer to millimeter levels, these environmentally friendly RPPGs are tailored for diverse reservoir conditions. Findings showcase the successful laboratory-scale creation and upscaling of RPPG products, offering adaptability to temperatures from 20 to 175°C, customizable sizes, swelling ratios (5 to 40 times), and re-crosslinking times spanning minutes to days. Field applications, notably in Alaska's West Sak field, demonstrate the efficacy of RPPG in resolving Wormhole/Void Space Conduit issues. The paper outlines preferred functionality, properties, evaluation methods, application conditions, and field outcomes, emphasizing RPPG's amalgamation of PPG advantages and in-situ gels into a singular composition, mitigating uncertainties while markedly improving plugging efficiency in fractures and conduits through a rubber-like bulk gel formation. This comprehensive review presents RPPG as a pivotal innovation, poised to revolutionize conformance strategies in many mature oilfields, offering a promising solution to prevailing reservoir challenges
Huff-N-Puff Foam Injection in Naturally Fractured Carbonates Using Supercritical CO2
Authors: Elkhatib O. , Abdallah M. , Elnaggar H. , Hanamertani A. S. , Al-Shalabi E. , Ahmed S. 
Published: April 2024

Abstract
Foam injection into naturally fractured reservoirs unequivocally has superior merits over pure gas injection. In this study, we present a novel foam generation strategy that incorporates the co-injection of surfactant and supercritical CO2 with huff-n-puff technique for the efficient diversion of the foaming gas into the rock matrix of fractured carbonates. A series of high pressure and temperature experiments were performed in fractured Indiana limestone cores with different permeabilities. First, gas injection was attempted to displace the oil from the fracture followed by foam flooding through the co-injection of a zwitterionic surfactant as a foaming agent and supercritical CO2. Then, a soaking period commenced at 200 psi above the preset pore pressure. Another co-injection of the foaming agent and scCO2 was carried out thereafter. The effect of the soaking pressure was evaluated by further utilizing 500 psi above the preset pore pressure in a subsequent soaking cycle. Similarly, this step was followed by a final foam injection to evaluate the potential increase in oil recovery.
The incremental recovery by foam injection over gas flooding, i.e., 21-24%, was attributed to the foam invasion into the permeable pathways in the rock matrix while the selective diversion of surfactant solution and the increase in foam strength were the responsible mechanisms for oil recovery from the low-permeability core. In the latter case, the gradual evolution of foam strength was corroborated by the rising pressure drop across the fractured core. Besides, the imbibing surfactant solution across the fracture surface behind the foam front drove the crude oil production along the path ahead of the foam front, aligning with the mechanism of countercurrent imbibition. Subsequent soaking of the foam into the fractured cores managed to provide enough pressure and time for the invading scCO2 to develop hydraulic conductivity throughout the rock matrix mobilizing and relocating crude oil from previously inaccessible and deep pores toward fracture-neighboring pores. Subsequent foam injection produced this mobilized oil inducing an incremental oil recovery of 6% and 17% from the high- and low-permeability cores, respectively. Higher soaking pressure yielded even more oil recovery highlighting the role played by the scCO2 phase pressure in overcoming the threshold capillary pressure of rock matrix in mobilizing their resident oil and brine phases. As a result, the proposed foam huff-n-puff technique has proven to produce significantly higher oil recoveries from both high and low permeable limestones. Besides, tighter rocks with lower permeability would have the greatest benefit from the proposed procedure which indicates its promising potential performance in unconventional and ultra-tight reservoirs.
An Improved Reservoir Understanding of the Impact of Initial Oil Composition and Residual Oil Saturation on Brine Composition and Calcite Scaling During CO2 – WAG EOR in Carbonate Reservoirs
Authors: Gusmao P. B. , Mackay E. J. , Sorbie K. S. 
Published: April 2024

Abstract
This paper provides an improved understanding of the impact of initial oil composition and residual oil saturation on brine composition and calcite scaling during CO2 Water-Alternating-Gas (WAG) Enhanced Oil Recovery (EOR) in carbonate reservoirs. It assesses the impact of different initial oil compositions and residual oil saturations in the reservoir using reactive transport modelling. Geochemical parameters, such as concentrations of CO2, Ca2+, HCO3- and pH are analysed as the propagating injection fronts reach the producer block.
The study uses a 1D model of WAG injection in a carbonate core, assuming a light oil and desulphated seawater injection into calcite as the rock substrate. The isothermal reactive transport modelling is performed using a compositional reservoir simulator coupled to a geochemical model that uses the WOLERY database. Formation water and injected water compositions are based on published data for Brazilian pre-salt fields. Henry's Law is used to calculate CO2 partitioning, particularly from residual oil into injected brine. Typically, solubility of CO2 will be greater in the injection than in the formation brines.
The results show that the higher the residual oil saturation, the longer that the injected brine becomes saturated with CO2 before the CO2 is depleted from the oleic phase. Hence, calcite dissolution due to acidification of the injection brine continues for longer, the higher the residual oil saturation. Therefore, calcium and bicarbonate concentrations remain high for longer in the produced brine after injection water breakthrough, increasing the scaling risk.
The scale risk becomes even greater in reservoirs with an initial oil composition rich in CO2. This is because there is more CO2 dissolved in the oil phase which will partition into the brine during the water injection cycle. As a result, the waterfront becomes more reactive for longer and hence dissolves more calcite, thus leading to a higher level of calcite scaling in the production system.
The conclusion is that CO2 partitioning from the oleic to the injected aqueous phase has a greater impact on in situ calcite dissolution and reprecipitation in the producer wells than does CO2 partitioning from the injected gas directly into the aqueous phase.
This work demonstrates, for the first time, how the residual oil saturation and initial oil composition impact geochemical reactivity in carbonate reservoirs, affecting the extent of in situ fluid-rock interactions. It demonstrates that the higher the CO2 concentration in the initial oil and the higher the residual oil saturation, the greater the calcite scaling risk in production wells during water breakthrough, with the residual oil facilitating mass transfer into injected brine.
Evaluation of Future CO2 Injection in Denver City Field for Enhanced Oil Recovery and CO2 Storage
Authors: Mukhtar Muhammad Haseeb , Ehlig-Economides Christine , Behm Ed , Zargar Zeinab , Lawson Jacob , Saihood Tariq , Yao Shengyu 
Published: April 2024

Abstract
Operating companies are finding that mature oil fields close to CO2 pipeline and processing infrastructure may offer an attractive option for enhanced oil recovery with improved returns aided by 45Q CO2 storage incentives. This case study evaluates future EOR and CCUS scenarios for the Denver City field in West Texas. Forecasts consider multiple options ranging from requiring little to no capital (more injection into existing patterns) to significant investment including the additional drilling of project expansion wells to prospective pattern areas.
The evaluation of the Denver City field with more than 50 wells penetrating a 50 ft oil column and 240 ft of residual oil zone included the historically active 1000-acre area includes surrounding area expanding evaluation considerations to about 5200 Ac for monitoring the area of potential CO2 influence. Analog Wasson Field information filled data gaps. Inter-well connectivity models suggested well constraints and identified workover opportunities. These analyses supported forecast assumptions made for continuous injection and WAG scenarios. Mature field areas with past CO2 injection for EOR purposes are contrasted with new patterns available for CCUS.
Out of the nine active inverted 5-spot patterns, six mature southern patterns offer diminishing EOR returns from additional CO2 injection. Converting adjacent waterflood patterns to continuous CO2 injection followed by water alternating gas (WAG) provides the best enhanced oil recovery (EOR) and CO2 storage value with less recycle volumes. Depending on the level of incentive provided to the EOR project, additional drilling may be warranted to extend oil recovery on the edges of the field and maximize the CO2 storage into additional available pore space.
Dimensionless modeling provided forecasts for various options while 45Q incentives are active. A low investment case injecting significantly more CO2 into existing CO2 patterns showed poor performance and efficiency. Horizontal wells added to the project may improve near term cashflow while providing future wells that can be used as in the CCUS project as injection wells or maintained as producing wells. Performance to date shows improved oil recovery from both main oil column and the residual oil zone due to CO2 injection. Based on these results, short-term and long -term recommendations address long-term CO2 storage volumes as well as expansion considerations.
45Q tax incentives for CCUS projects provide support for marginal mature field use for carbon capture projects. Maximizing short term oil production and CO2 retention while minimizing gas recycling may alter the priorities of conventional CO2 EOR flooding. Oil field anticlines provide excellent candidates for CCUS projects.
Polymer Solution Preparation and Quality Control at Milne Point
Authors: Aitkulov Almas , Redwine Connor , Alvord Jeremy , Edwards Reid , Seright R. S. 
Published: April 2024

Abstract
This paper focuses on solution preparation and quality control activities associated with the Milne Point polymer flood on the North Slope of Alaska. This project uses ten different polymer injection locations with a variety of skid types and configurations, which had a notable impact on polymer quality control and dissolution operations. Compared with bulk 500-750-kg polymer bags, silos greatly improved the storage capacity and increased the overall quality of polymer wetting in system. Silos also required less physical effort when transferring polymer. Polymer hydration skids that were made inhouse by the polymer supplier were more reliable and experienced fewer polymer solution quality and startup issues than those that were outsourced. These inhouse skids also used a uniform programming software that made it relatively easy to train the operators on new hydration skids. For pumping polymer mother solution, triplex pumps provided the best run time and were most maintenance-friendly, compared with diaphragm or triple screw pumps. Although polymer solutions could be prepared that met our target viscosities without using a nitrogen blanket, corrosion and iron particulates raised substantial reliability and injectivity concerns if nitrogen blanketing was not used—especially when using black iron piping and when the make-up water contained dissolved iron. Inline static mixers were ineffective in mixing mother solution with dilution water when the mixing occurred close to the wellhead. Mixing the two streams too close to the wellhead led to substantial variations in wellhead viscosity measurements. Dedicating individual pumps for injection into a given well provided desirable flexibility in controlling rates and concentrations of polymer for the well. Monitoring produced salinity and polymer concentration provided useful insights about improved sweep and polymer retention associated with the polymer flood. The observed field behavior was consistent with laboratory studies indicating a "tailing" phenomenon associated with polymer retention at Milne Point.
Deploying Polymer Flood in a Secondary Recovery Mode using Horizontal Injectors in a Complex Heavy Oil Field in the South of the Sultanate of Oman
Authors: Al Yaaribi Z. H. , Al Sulaimani H. , Karpan V. 
Published: April 2024

Abstract
Over the past decade, Petroleum Development Oman (PDO) has accumulated significant experience studying and applying polymer flooding under various oil reservoirs and field conditions. In addition to ongoing commercial polymer flooding in the Marmul oil field, the company is actively pursuing polymer projects in more complex and mature oil fields. To accelerate the deployment of these projects, PDO capitalizes on in-house, regional, and worldwide experience. This paper discusses the implementation of polymer flooding in Thayfut a heavy oil field (oil viscosity above 600 cP) in a complex Gharif formation with a thin oil column. The field is produced under the depletion mode with the pressure support supplied by the aquifer. Due to the significant mobility contrast between viscous oil and water, the production water cut has increased significantly, limiting the oil recovery. Polymer flooding with horizontal injectors (parallel to existing horizontal producers) was proposed to achieve higher oil recovery at lower greenhouse gas (GHG) emission intensity. Additionally, this paper describes the development concept, reservoir modeling, and forecasting details. The scope of surface development is also discussed regarding water supply options, polymer facility, and polymer distribution mode.
It is demonstrated that applying polymer in a secondary mode offers significant benefits due to high remaining oil saturation, especially for fields with high permeable formation and oil viscosity. Laboratory and field data from similar projects were used to benchmark the inputs for the dynamic models that were used to forecast the oil recovery due to polymer flooding.
Despite the encouraging oil production forecast due to the polymer flooding, several alternative development scenarios were investigated, including infill drilling and waterflooding. It was found that injecting polymer is the best option due to the highest ultimate oil recovery and lowest GHG emission intensity of produced oil. Polymer project economics is also advantageous, including the surface optimizations applied regarding polymer facility and distribution. The project is expected to accelerate the production peak, reduce decline, and allow better facility and urban planning design.
This paper illustrates the application of polymer injection in a secondary mode in a complex Gharif reservoir with heavy oil. This method can lead to a new polymer application strategy in future PDO fields.
Deciphering the Potential of Surfactant-Assisted CO2 Mobility Control: Insights into the Transient Foam State
Authors: Ding Lei , AlOtaibi Mohammad , AlYousef Zuhair , AlSofi AbdulKareem M. 
Published: April 2024

Abstract
Foam-assisted CO2 mobility control can enhance CO2 utilization and storage efficiency during enhanced oil recovery and carbon sequestration processes. CO2 is typically injected at larger gas fractions (fg) to reduce the surfactant costs, which, however, may result in significant retardation of foam generation/propagation due to high minimum pressure gradient (MPG) and surfactant adsorption. This study aims to minimize the transient foam state and optimize the foam process for maximizing the CO2 utilization capacity.
The design of a foam process mainly focuses on the foam behavior at steady states, e.g., foam apparent viscosity and transition foam quality. However, the foam steady state may take several pore volumes (PVs) of throughputs, which is difficult to achieve in the field tests. Therefore, the transient foam behavior (e.g., the onset of foam generation and foam apparent viscosity in the first several PVs) is more critical and needs greater attention. We evaluate a CO2 foaming system using switchable amine surfactants by performing core-flooding experiments and numerical simulations at 65°C and 150 bar operating conditions.
The evolution of CO2 foam apparent viscosity at various fg shows that the foam becomes stronger, yet the transient state becomes longer at elevated fg. The results indicate that the retardation of foam generation at high fg is resulted from high MPG and a low in-situ surfactant concentration. The in-situ surfactant concentration is influenced by the injected surfactant concentration, adsorption on the rock, dispersion, and surfactant partitioning behavior. The simulation results suggest that the retardation at transient states can be minimized by tuning the surfactant concentrations, fg, and injection sequence, to reach the strong foam and high CO2 saturation in a much shorter injection period. The experimental results demonstrate that foam is triggered more rapidly at low fg. Moreover, the retardation of foam propagation at transient states is further reduced by injecting a high surfactant concentration and a low fg in the initial stage and then progressively proceeding to higher fg and lower surfactant concentration. It is hypothesized that high surfactant concentration can rapidly compensate for the dilution of surfactant (by partitioning, dispersion, and adsorption) and enhance the foam generation and its propagation.
The retardation of foam at transient states will cause a series of operational and economic problems, thus, should be minimized as much as possible. An improved injection strategy is developed in this study to diminish the retardation of foam at the transient state from 16 PV to 1.9 PV, which can maximize the mobility control of CO2 and storage efficiency of CO2 in saline aquifers.