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Collaborating Authors
Block 34/7
Using Foam Treatments to Control Gas-Oil Ratio in Horizontal Producing Wells at Prudhoe Bay
Davis, T. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Monette, M. (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, USA) | Nelson, J. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Mayfield, C. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Cunha, K. (Hilcorp Alaska LLC, Anchorage, AK, USA) | Nguyen, Q. (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, USA)
Abstract Production at Prudhoe Bay is constrained by gas handling. The objective of this project was to develop a foam injection strategy to reduce gas mobility in producing wells and increase field oil production through reduction of producing gas-oil ratio. Aqueous foam has been extensively studied through laboratory and field experiments for gas mobility control to improve sweep efficiency in gas flooding. However, the potential of foam injection into horizontal producers for mitigating unwanted gas production has not been well understood. In this work, a unique design of laboratory experiments was developed to optimize surfactant formulation for foam generation and stability under the conditions of target gas saturated zones in the Ivishak sandstone reservoir. Gas blocking capacity for different foam placement and flowback strategies in reservoir cores were evaluated to identify important factors for optimized field process design. Based on lab results, five producing wells were selected for repeat injections of brine using varying volumes. Flowback results described the gas-blocking potential and determined optimal foam injection volume for each well. Two of the same wells were then treated with foam and flowed back. Experimental results show that oil tolerance is not a critical surfactant screening criterion for these particular reservoir conditions as the targeted treatment zones are the high permeability channels which have likely experienced a large amount of gas channeling. The threshold surfactant concentration, above which foam blocking capacity did not further improve, was significantly lower than that used in previous lab and field studies. Moreover, foams with an initial apparent viscosity above 50 cP remarkably delayed and reduced gas production rate for over a week in short cores at varying applied pressure gradients. The laboratory observations led to a new foam injection strategy that aims to place surfactant deeper into the gas zone by an optimal foam drive. Field trials demonstrated strong technical success of both brine and foam treatments to block gas production and reduce producing gas-oil-ratio (GOR). Flowback following brine injection demonstrated temporary GOR reduction for a period of about one week. Repeat brine treatments, of varying injection volumes, described the near-wellbore pore space and informed optimal foam treatment volume for each well. Both foam treatments resulted in reduced gas mobility, reduced producing GOR, and longer duration of these effects compared to brine gas blocking. Foam gas blocking effects lasted up to 70+ days, resulting in significant incremental oil production from the field. Foam provides a novel method to decrease producing GOR in horizontal wells in Prudhoe Bay and increase field oil production. Foam treatments are shown to be a cheaper alternative to well interventions, gas handling expansion, or other means of increasing production in a gas constrained system. This work has advanced our understanding of foam potential for gas shut-off in both vertical and horizonal producing wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (38 more...)
Innovative In-Situ Foam Generation and Injection Strategy Using Greenhouse Gases for Conformance Control
Hanamertani, Alvinda Sri (Department of Energy and Petroleum Engineering, University of Wyoming, Laramie, WY, USA) | Elkhatib, Omar (Department of Energy and Petroleum Engineering, University of Wyoming, Laramie, WY, USA) | Yu, Ying (Center for Economic Geology Research, School of Energy Resources, University of Wyoming, Laramie, WY, USA) | Ahmed, Shehzad (Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE)
Abstract Mobility control is one of the most pressing challenges facing greenhouse gas injection for enhancing oil recovery (EOR). A promising solution for this issue was portrayed in employing foam technology due to its favorable mobility ratio and ability to delay the breakthrough of the injected gases. However, the costs pertaining to the utilization of expensive foaming chemicals have prompted economical complications for the wide scale application of the foam EOR techniques. In this study, we compared different foam injection strategies with the economical aspect in mind and introduced a novel injection approach with superior techno-economic performance in generating CO2 and CH4 foam in-situ at harsh pressure and temperature conditions. Four foam injection strategies were evaluated in terms of their impact on the mobility reduction of the in-situ generated CO2 and CH4 foams. In the methane foam case, the co-injection mode produced high mobility reduction factor (MRF) compared to the single cycle surfactant alternating gas mode (1-SAG). However, the multicycle strategies including the SAG and the proposed gas alternating foam (GAF) outperformed the co-injection mode yielding MRFs of 289 and 336, respectively. The steady state co-injection of CO2 and surfactant solution, however, produced less mobility control compared to the 1-SAG mode. The multicycle SAG and GAF strategies provided more favorable mobility ratio, with MRFs of 99 and 120 respectively, when compared with the other injection strategies of CO2-foam. Consequently, the novel GAF injection and in-situ foam generation strategy displayed the most prominent mobility control potential for both gases. Besides, this injection strategy decreased surfactant consumption by more than 70% compared to the other injection strategies shedding light on its worth as the most promising economical foam generation strategy in EOR field applications.
- Asia (1.00)
- Europe (0.68)
- North America > United States > Texas (0.46)
- (4 more...)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Word Group > San Andres Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Wolfcamp Reef Formation > San Andres Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Wolfcamp Lime Formation > San Andres Formation (0.99)
- (22 more...)
Abstract There has been substantial development of modelling tools for viscous instabilities and multi-phase flow in recent years. This has enabled better opportunities of modelling near-miscible WAG (Water-Alternating-Gas), respecting gas fingers and simultaneously representing more correct phase mobilities. The objectives of this paper are to demonstrate advanced near miscible WAG modelling including WAG three-phase hysteresis, and present cases of Foam Assisted WAG (FAWAG) revisited with several novel modelling approaches. The numerical modelling has been performed using commercial reservoir simulators, STARS and GEM from CMG. The methodology of describing viscous fingering, analogue to Sorbie et al. (2020), is a 4-stage approach: (1) selection of fractional flow to maximize total mobility; (2) derivation of the relative permeability; (3) establishing an appropriate random correlated permeability field; and (4) simulating the process with a sufficiently fine grid. Simulations have been performed in 3D models using fine grid and random Gaussian permeability field. Three-phase fluid flow modeling used the GEM implemented version of Larsen and Skauge WAG hysteresis model, and the CMG foam model. We have used two differentrock permeability models, a standard vertical layered model, and a model with heterogeneous permeability within each layer. The fluid flow functions were either a conventional or a WAG hysteresis model respecting three-phase mobilities and phase trapping. The impact on gas finger development was analyzed and was based on simulation production data, but also on the in-situ fluid distribution. WAG hysteresis dampened to some degree the gas fingers but was able to show oil bank formation and enabled interpretation of in-situ fluid diversion. We have expanded the numerical modeling to include foam and specifically the foam assisted WAG (FAWAG) process. This is a revisit of an earlier study (Skauge et al. 2002 on Foam Assisted WAG, a Summary of Field Experience at the Snorre Field), but now updated with the novel modelling approaches. Many factors influence foam strength, with mobility reduction factor (MRF) as the key factor. We used the GEM version of foam description, with MRF as the main factor defining the foam properties. In this approach we were able to describe the reduction in GOR, but also the oil banking and consequently the extra oil production due to FAWAG injection. Simulation studies show that it is possible to include complex modelling in a commercial simulator. The advanced models enable a more correct history match of production and a more systematic analysis of local diversion of fluid flow due to WAG and FAWAG that would not be possible using a conventional approach. With the new approach, improved decisions for field development can be made.
- Asia (0.94)
- North America (0.94)
- Europe > Norway > North Sea > Northern North Sea (0.49)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Northeast Marine Region > Cantarell Field (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...)
The Effect of Multiple Cycles of Surfactant-Alternating-Gas Process on Foam Transient Flow and Propagation in a Homogeneous Sandstone
Adebayo, Abdulrauf R. (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals (Corresponding author)) | Rezk, Mohamed Gamal (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals) | Badmus, Suaibu O. (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals)
Summary Years of laboratory studies and field tests show that there is still uncertainty about the ability of foam to propagate deep into a reservoir. Many factors have been identified as potential causes of nonpropagation, the most concerning being the lack of sufficient pressure gradient required to propagate foam at locations far from the point of injection. Most researchers that investigated foam propagation did so by coinjecting surfactant and gas. Coinjection offers limited information about transient foam processes due to limitations in the experimental methods needed to measure foam dynamics during transient flow. Foam injection by surfactant-alternating-gas (SAG) has proven to be more effective and common in field application. Repeated drainage and imbibition cycle offer a more favorable condition for the quick generation of foam. Foam can also be propagated at a lower pressure gradient in SAG mode. The objective of this study is to experimentally investigate how transient foam dynamics (trapping, mobilization, and bubble texture) change with multiple cycles of SAG and also with distance from the point of injection. A pair of X-ray source and receiver, differential pressure transducers, and electrical resistance sensors were placed along a 27-cm long, homogeneous, and high-permeability (KL = 70 md) Berea sandstone core. Foam was then generated in situ by SAG injection and allowed to propagate through the core sample under a capillary displacement by brine (brine injection rate = 0.5 cm/min, Nca = 3×10). By use of a novel analytical method on coreflood data obtained from axial pressure and saturation sensors, we obtained trapped foam saturation, in-situ foam flow rates, apparent viscosities, and inferred qualitative foam texture at different core sections. We then observed the following: (i) Maximum trapped foam is uniform across the core sections, with saturation ranging from 47% to 52%. At the vicinity of foam injection, foam apparent viscosity is dominantly caused by gas trapping. At locations farther away, foam apparent viscosity is dominated by both gas trapping and refinement of foam texture. (ii) Cyclic injection of foam further enhances the refinement of foam texture. (iii) Textural refinement increases foam apparent viscosity as it propagates away from the point of injection. (iv) As the foam strength increases, the average gas flow rate in the core sample decreases from 0.5 cm/min to 0.06 cm/min. (v) There is no stagnation of foam as remobilization of trapped gas occurs during each cycle at an average flow rate of 0.002 cm/min.
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Webster Formation (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Monterey Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- (11 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Equinor's Hywind Tampen wind farm, the world's largest floating offshore wind farm, opened in August. The farm consists of 11 wind turbines with 88 MW of capacity that will cover around 35% of the annual power demand for five platforms at the Snorre and Gullfaks oil and gas fields in the North Sea, according to Reuters. The farm is expected to reduce 200 000 tonnes of CO2 annually. "With Hywind Tampen, we have shown that we can plan, build, and commission a large, floating offshore wind farm in the North Sea. We will use the experience and learning from this project to become even better," Siri Kindem, head of Equinor's renewables business in Norway, said in a company press release.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea (0.48)
- Europe > Netherlands > North Sea (0.48)
- (2 more...)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.94)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.94)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.94)
- (14 more...)
Abstract Meeting the Paris Agreement targets and rapidly transitioning towards renewable energy are critical. Despite significant renewable energy growth, projections indicate fossil fuels will meet almost half the UK's energy demand by 2050. The oil and gas industry is facing increasing decarbonization mandates due to environmental concerns and the need for a sustainable energy future. However, the UK is unlikely to completely achieve its Nationally Determined Contribution (NDC) target. Offshore oil and gas industry emissions are primarily due to energy-intensive processes that could be significantly reduced by shifting towards more sustainable practices and electrifying these processes. The West of Shetland region holds strategic significance in energy security, economic contributions, and potential for further exploration. The rapidly evolving offshore wind power sector and technological innovations in this field present a promising path towards a sustainable energy future. However, the electrification of oil and gas assets in the West of Shetland area will encounter challenges relating to grid connectivity, wind intermittency, environmental impact, and potential large-scale wind power generation elsewhere in the UK. Three key network design options are suggested for supplying required offshore electricity: a coordinated approach, an individual approach, and a local supply approach. There are three key groupings in the West of Shetland region: the Clair grouping, Schiehallion-Lancaster-Solan, and Rosebank-Cambo. Each has potential for electrification, but also unique challenges to be addressed. The adoption of renewable energy and energy storage technologies for oil and gas facilities in the West of Shetland area involves a variety of factors. Initial costs can be substantial, especially offshore, but these could be offset in the future due to tightening emissions regulations and carbon pricing. Older assets nearing their end of life may not be worth electrifying. Overcoming these challenges necessitates a collaborative strategy among industry players, the government, and regulators. Norway is leading in electrification, while the UK North Sea is moving much more slowly. A coherent energy policy for the West of Shetland area addressing oil and gas developments alongside renewable energy developments appears essential.
- Europe > United Kingdom > Atlantic Margin > West of Shetland > West Shetland Basin > Block 204/9 > Cambo Field > Corona Ridge Formation (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > West Shetland Basin > Block 204/10 > Cambo Field > Corona Ridge Formation (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/9 > Clair Field (0.99)
- (75 more...)
Abstract Reservoir fluid estimation for exploration prospects can be random and of large uncertainties. Typically, the reservoir fluid estimation in a prospect can be derived from a geochemical basin model or seismic data interpretation with regional knowledge. An analog reservoir fluid sample will often be selected for reservoir fluid estimation. Such analog samples can come from a neighboring field at some distance. The best approach for accurate reservoir fluid estimation is based on the reservoir fluid data from nearby wells when available. This paper demonstrates that mud gas data from wells inside or near the exploration prospect provides a much-improved reservoir fluid estimation. In our previous work, we developed novel methods to estimate reservoir fluid properties from advanced and standard mud gas data. This paper uses three field cases to illustrate how mud gas data can be translated into reliable reservoir fluid estimations for prospect evaluation for potential developments. We have standard mud gas data available for the three field cases. The first two cases are examples of gas and oil prospect evaluations based on legacy wells without reservoir fluid samples. The last example is a prospect evaluation of overburden for potential production. For the first prospect, reservoir gas has been produced from high permeable formations for many years, and the field is in its late life. To extend the gas production, the low permeable formation with a large reserve becomes the new target for evaluation. Due to the poor quality of the target reservoir zone and the need to stimulate production, it is important to confirm the reservoir gas in the formation. The reservoir fluid estimation is crucial for the decision of an appraisal well and the potential development of the prospect. We utilized the mud gas data from the legacy well to improve the reservoir fluid estimation. The new reservoir fluid estimation is gas-prone with leaner gas than the reservoir gas under production. The second prospect locates an area with multiple oil fields but various oil qualities. The well from the prospect has no PVT samples, making the prospect evaluation highly uncertain. We used mud gas data to estimate the oil quality of the prospect and the reservoir oil gradient in the reservoir zones. The last prospect is the overburden of a large oil field. Due to the good experiences from near fields on production from overburden, the reservoir fluid estimation is required to distinguish if the reservoir fluids in the overburden are similar to those in reservoir zones or have an independent fluid system. We used mud gas data from a new production well crossing the overburden formation. The results show the reservoir fluids in the overburden are close to those in reservoir zones. The new mud gas data method provides accurate reservoir fluid estimations for three prospect evaluations with significantly reduced uncertainty. The implementation of the new method for prospect evaluation has not been reported previously. Due to the wide availability of standard mud gas data, the new method can be broadly implemented for prospect evaluations and generates large business impacts.
- Europe (1.00)
- North America > United States > Texas (0.29)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Overview > Innovation (0.54)
- Research Report > Experimental Study (0.34)
- Geology > Sedimentary Geology (0.96)
- Geology > Geological Subdiscipline > Geochemistry (0.34)
- 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)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
We automatically extract lithofacies from a modern Mississippi point bar, in False River Louisiana U.S.A. We use K-means clustering with 5 types of data and identify 6 reasonable lithofacies. We integrate different geophysical data such as Electrical Conductivity (EC), permeability calculated from a Hydraulic Profiling Tool (HPT) log, as well as visual core descriptions, and grain size measurements. Multivariate statistical techniques such as the Generalized Additive Model (GAM) allow us to interpolate and increase the limited grain size dataset into sections of the wells where there are no such measurements. GAM is an advanced regression fitting technique which produces robust results and a high R-square ratio. We also enhanced grain size interpolation by implementing a hybrid model which also considers lithology in each well interval.
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (1.00)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray 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)
- (11 more...)
Equinor announced this week the opening of the Hywind Tampen wind farm that was built to help power some of its offshore oil and gas platforms. With a capacity of 88 MW, the 11-turbine project stands out as Norway's first offshore wind installation and also the world's largest to employ the floating concept. Equinor is also hoping that the new floating asset becomes a template for future wind projects in the deepwater where there are just a small handful. Located almost 140 km offshore Norway, each of the 8-MW turbines are installed in depths ranging from 260 to 300 m. The turbines have been operational since November but Equinor said they achieved full capacity for this first time this month.
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.94)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.94)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.94)
- (14 more...)
Overburden 4D seismic analysis: Influence of stress and pore-pressure changes accounting for elastic contrast between a reservoir and its anisotropic surrounding rocks
Yan, Hong (Norwegian University of Science and Technology) | Bakk, Audun (SINTEF) | Duda, Marcin (Norwegian University of Science and Technology, SINTEF) | Holt, Rune Martin (Norwegian University of Science and Technology, SINTEF) | Lozovyi, Serhii (SINTEF)
ABSTRACT Time-lapse (4D) seismic data analysis is widely used to monitor producing hydrocarbon or CO2 storage reservoirs and their surroundings. The influence of potentially significant undrained pore-pressure changes around depleting (or injected) reservoirs appears to be neglected in most previous studies. The 4D seismic response in the overburden depends on the stress changes and strains induced by the reservoir. These alterations may challenge stable infill drilling and well integrity. We have used anisotropic static elastic moduli from laboratory measurements for two different field shales to predict stress changes and strains in the surroundings of a depleting reservoir through geomechanical modeling. These mechanical changes are used to quantify undrained pore-pressure changes using anisotropic poroelastic theory constrained with Skempton parameters. Finally, an empirical rock-physics model quantifies the impact of these poroelastic changes on vertical velocity changes and time strains. This model explicitly quantifies the individual contributions to vertical velocity changes from undrained pore pressure, mean stress, and shear stress above (and below) the depleting reservoir. We find that a stiffer surrounding rock exhibits significantly larger vertical time strains and time shifts in the overburden as compared with softer surrounding rocks because of promoted arching. Undrained overburden pore-pressure changes significantly contribute to overburden velocity changes and time shifts. Ignoring anisotropy in the Skempton parameters can lead to overestimating the overburden undrained pore pressure and time shifts after reservoir depletion. The anisotropy in static stiffnesses significantly impacts the dynamic changes in the vertical direction, and the dynamic changes are particularly pronounced in the vicinity of the reservoir. We find how a tailored rock-physics model can link 4D seismic data and geomechanics to separate stress, strain, and pore-pressure changes — all essential for optimizing drilling and production.
- Europe > Norway (0.68)
- Europe > United Kingdom > North Sea > Central North Sea (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.74)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/30b > Shearwater Field > Fulmar Formation (0.99)
- (15 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)