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This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. An 18-well numerical-simulation model was built to represent an operator’s Lower Shaunavon waterflood-pilot area. Numerical simulation was used, and a history match on the pilot area was performed.
Winning innovators focused on environment, safety, and operational efficiency. Through a combination of reducing operational emissions and offsetting projects, the shale-gas producer has set a new benchmark for its sector. Add Denbury Resources to the list of oil companies filing for bankruptcy protection with a plan that may make for a quick trip through the debt-reduction process. Although based on “intensity” and not “absolute” emissions, oil giants say it’s a step toward net-zero goals for 2050. An independent study pegged the cost of the project at about $2.6 billion, 80% of which Norway’s government planned to fund.
The latest updates on the North American shale sector’s efforts to consolidate and restructure. The V-shaped recovery for oil demand is likely to end up looking lopsided. The recent rapid rise in consumption is expected to stop before it gets back to the peak seen earlier this year. In the region’s second bankruptcy of the month all of the operator’s assets will be sold to a private equity energy group, pending court approval. The Gulf of Mexico E&P exited its first bankruptcy quickly with a strategy that included the acquisition of Noble Energy’s GOM assets, which increased its production volumes 25% when the WTI approached $80/bbl.
The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. The participants are exposed to the analysis of various elements that help in production system starting from reservoir to surface processing facilities and their effect on the performance of the total production system. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Achieving high hydrocarbon recovery is challenging in unconventional tight and shale reservoirs. Although EOR/EGR processes could potentially improve the recovery factor beyond the primary depletion, large-scale field application of these processes are not yet established in these reservoirs. This session will focus on the latest research trends, modelling and experimental work to better understand issues involved in improved economic recovery from such reservoirs.
In order to produce from shale gas reservoirs hydraulic fracturing is required. This stimulation technology facilitates the interconnection of the multiple pore systems with the wellbore. Particularly, shale gas reservoirs exhibit a dual porosity system linked to the free and adsorbed fluid phases, being the adsorbed phase a significant control on the long-term production. The adsorbed volume is strongly related to the total organic carbon (TOC) and thus, it is often assumed that higher hydrocarbons in place occur within the high TOC intervals. This study evaluates this relationship and the impact of the adsorbed phase to OGIP (original gas in place) and production behaviors. Analysis of petrophysical data and log-derived TOC of the Duvernay Formation reveals that variations in mineralogy impacts the quantity of TOC. It is observed that increase in carbonate contents correlate with lower organic contents, whereas increase in quartz and clays correlate with higher organic contents. Results of Langmuir isotherms indicate that methane adsorption capacity is directly proportional to the TOC content. In addition, adsorption capacity is corrected for the free pore volume captured by the adsorbed layer in the reservoir conditions. This correction increased the adsorption capacity by 20-25%. Further, this study analyzes production data of two multi-fractured horizontal wells by analyzing the relative contribution of the adsorbed phase to the free gas. It is found that contribution of the adsorbed phase is maximum during the initial phase of the production cycle which declines as the reservoir pressure drops. The estimated relative contribution of the adsorbed phase to OGIP is nearly 50% which is significant to be considered negligible. Further, the contribution from the adsorbed phase is found to be 45% in the early phase of the production which drops down to 25% after 5 years of the production. Finally, this study illustrates that the relation of TOC with fluid characterization and recoverable reserves is complex and should be analyzed with the variation in adsorption and desorption capacity of lighter and heavier components.
Cyclic gas injection in hydraulically-fractured wells has been successfully applied as an enhanced oil recovery (EOR) method in tight unconventional basins such as the Permian and Eagle Ford. However, displacement processes (continuous gas, solvent or water injection) such as those piloted in the relatively more permeable Bakken formation have not been considered in tighter basins. In this work, we present a novel displacement process that uses alternating injecting and producing hydraulic fractures to flood the inter-fracture region around a horizontal well. We demonstrate that the method is feasible as long as suitable fracture geometries can be generated.
A reservoir geomodel of a typical Montney gas condensate reservoir was constructed using publicly available data. Rock mechanics parameters were integrated into the model alongside completion and pumping schedule information to predict hydraulic fracture propagation and geometries representative of the typical stimulated volumes in Montney. A compositional numerical reservoir simulator was then used to test the proposed EOR process in a gas condensate reservoir where we forecast liquid recovery under different frac-to-frac continuous gas injection flooding scenarios. Sensitivities to study the effect of fracture spacing and complexity, solvent composition, starting time of gas injection, and matrix permeability were performed.
With simultaneous injection and production from alternating hydraulic fractures, it is possible to flood the volumes between them and consequently avoid the drawbacks of huff ’n’ puff processes. By using a more rigorous fracture description, we can reproduce the interactions between fractures and determine how they affect the conformance of the displacement front.
Modeling results showed that frac-to-frac displacement process can significantly improve the condensate recovery compared to primary or even huff n puff EOR process. They also showed that the frac-to-frac EOR process is feasible only if the formation mechanical properties and in-situ stresses are such that the resulting hydraulic fractures exhibit aligned planar geometries. If high-intensity natural fracture networks are present, the hydraulic fractures tend to form complex geometries that negatively affect the conformance of the flooding front. The study also showed that there is an optimal spacing between the injecting and producing fractures that would allow for the efficient utilization of the EOR agent; this spacing was shown to have a strong dependence on matrix permeability. Composition of injected solvent and starting time of gas injection doesn’t seem to have considerable impact on incremental recovery due to frac-to-frac displacement.
Through a combination of reducing operational emissions and offsetting projects the shale-gas producer has set a new benchmark for its sector. Add Denbury Resources to the list of oil companies filing for bankruptcy protection with a plan that may make for a quick trip through the debt-reduction process. Although based on “intensity” and not “absolute” emissions, oil giants say it’s a step toward net-zero goals for 2050. An independent study pegged the cost of the project at about $2.6 billion, 80% of which Norway’s government planned to fund. The ministry said there is uncertainty about Northern Lights’ benefits and that it could prove to be unprofitable.
Low oil recovery factors and rapid decline rates are key challenges in developing shale and tight oil formations. Despite encouraging gas Huff-n-Puff (HnP) field pilot results, the oil-recovery mechanisms are still not well understood. This paper investigates the oil-recovery mechanisms during a natural gas (C1 and a mixture of C1/C2 with the molar ratio of 70/30) HnP process on ultralow-permeability Montney plugs. This study comprises of two sets of tests that are conducted under core-plug and bulk-phase conditions. To investigate oil-recovery mechanisms from an oil-saturated core plug, we used a custom-designed visualization cell to visualize the interactions at the surface of the plug during natural-gas injection (huff), soaking, and pressure-depletion (puff) processes under reservoir conditions of 2,000 psig and 50°C. This experimental setup simulates a 1-D gas diffusion process which is believed to occur at the fracture faces during the gas HnP process. To complement the core-plug tests, we conducted bulk-phase tests including (1) vanishing interfacial tension (VIT) to estimate minimum miscibility pressure (MMP), (2) constant composition expansion (CCE), and (3) visualization tests to study the phase behavior of gas-oil systems.
We observed four main oil-recovery mechanisms including vaporizing/condensing-gas drive, oil swelling, molecular diffusion, and solution-gas drive, from the core-plug and bulk-phase tests. In that, the major mechanisms are the oil swelling, molecular diffusion, and solution-gas drive during the injection, soaking and depressurization phases of the core-soaking tests, respectively. Oil swelling in C1 and C1/C2 tests appears to be pronounced during gas-injection and soaking phases. During the depressurization phase, the expansion of diffused gas leads to a significant flow of oil comingled with gas, observed at the surface of the plug. According to the MMP measurements, increasing mol% of C2 in the injection gas (0 to 29.7%) reduces MMP of the gas-oil system from 4,350 psig to 2,726 psig. The developed miscibility conditions by enrichment of injection gas enhance the diffusivity of gas into the oil phase and the plug during the soaking period. Vaporization of oil components into the gas phase and condensation of C1/C2 into the oil phase in the bulk-phase visualization tests lead to higher oil swelling in the C1/C2 test compared to pure C1 test. The results of CCE and bulk-phase visualization tests suggest that the addition of C2 to the injection gas increases oil swelling which may explain higher oil recovery by the C1/C2 mixture compared with pure C1 in the core-soaking tests.
Thanks to the advancements in and convergent of the two technologies of horizontal well drilling and hydraulic fracturing, the oil production from tight formations has become possible and economic. While hydraulically fractured horizontals wells (HFHW) have increased the productivity of these reservoirs, these wells typically see a sharp decline in hydrocarbon rate due to tight nature of these reservoirs.
Operators have improved oil recovery methods in these formations with the successful application of the secondary recovery method of waterflooding. This combination of HFHW and waterflooding has primarily been implemented in Canadian tight oil formations such as the Canadian Bakken Shale, lower Shaunavon, Viking, Belly River and Cardium. With the application of waterflooding on these HFHW, the one issue that operators are facing is the management of quick water breakthrough due to well to well communication through the network of induced or natural fractures resulting in poor sweep efficiency of waterfloods.
Conformance improvement using polymer gel technology, a polymer and a polymer specific cross-linker, has been a common practice in conventional assets for 30 years. The polymer solution is mixed with the crosslinker on the surface and the mixture becomes more viscous (due to the reaction between polymer and crosslinker) as it is pumped downhole and into the reservoir. The application of polymer gel technology in unconventional tight oil water floods requires a new approach and is most successful when approached in a systematic way starting with proper diagnosis and candidate selection followed by engineering design and field execution. After candidate selection and diagnosis of communication between wells, a treatment design is put together based on the level of communication as measured by the transit time between the two wells. The conformance treatment is implemented by bull heading the mixture of polymer and crosslinker and sequentially increasing the gel strength by increasing polymer concentration at fixed polymer to crosslinker ratio. The idea is to build pressure continuously throughout the treatment, an indication of polymer gel filling up the path of communication.
A new application for gel conformance technology, in tight oil waterfloods, as a cost-effective solution, to address the well to well communication and improve sweep efficiency is discussed in this article. Relatively smaller size and lower strength of gel, compared to the typical applications, makes the application of polymer gel in HFHWs unique and very effective. This paper will review multiple campaigns in Canadian Bakken from 2016 to 2018 and discuss the rate of success, incremental oil produced and longevity of these treatment. Opportunities to further optimize these treatments and the pitfalls have been recognized and discussed.