|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
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.
Cold heavy oil production with sand (CHOPS) is a relatively recent technology. As such, only a few case histories of its application over a number of years have been published. Nonetheless, those that are available provide insight into the application of this technology. A detailed Luseland field case history has been published. It had a long history (12 to 15 years) of slow production with reciprocating pumps, an attempt to produce with horizontal wells (6 wells, all failures), and then a conversion to CHOPS through reperforation and progressing cavity (PC) pump installation.
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.
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. Write-offs include billions for early-exploration-stage projects that the company will now cut.
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. Write-offs include billions for early-exploration-stage projects that the company will now cut. Phase 1 is expected to be operational in 2024.
Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction in the Latin American Region (LAR) has some of the highest and lowest values of CI and holds many opportunities to reduce carbon emissions and improve national wealth. Flaring and venting of associated or non-associated natural gas dramatically increases CI.
This paper applies peer-reviewed processes across broad averages of oil and gas activity in major fields around the world and compares them with both Latin American and North American oil plays. Ways to lower the carbon intensity for high CI fields in the region are discussed. Unique opportunities exist to minimize carbon intensity in both areas.
We perform well-to-refinery calculations of CI for major unconventional oil plays in all major Latin American fields, the largest North American unconventional plays and other major producing countries. This approach accounts for emissions from exploration, drilling & completions, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases.
Applied globally, OPGEE estimates show the highest values in areas with extensive flaring of natural gas and very heavy crude oils. Heavy oils require large energy inputs (e.g. steam flooding) and/or the use of light hydrocarbon diluents for transportation offset. OPGEE can be used to evaluate the CI impacts of public policy actions.
While both NA unconventional and LAR crudes will remain vital to regional and global supplies, unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments and regulators need to be able to avoid "locking in" development of suboptimal resources and providing incentives for shale operators to manage resources sustainably. Oil producers must prepare by refraining from developing marginal projects, eliminating flaring, optimizing hydraulic fracture treatments, using improved recovery methods (e.g. enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
We conducted a comprehensive analysis of approximately 7000 horizontal wells drilled in the Middle Bakken formation between 2007 and 2016 to assess the impact of well orientation on cumulative production. While it is common practice to drill horizontal wells "on-azimuth", that is, in the direction of the minimum horizontal stress (Shmin), there is a diversity of well orientations in the Bakken. Shmin is consistently oriented N42°W throughout the production area. Our analysis clearly demonstrates that wells drilled in the direction of Shmin ("on-azimuth") produce more barrels per foot than wells in other directions, both in the core area and across the entire Bakken play. However, the amount of uplift gained from drilling on-azimuth wells decreases as the field matures, which we hypothesize is due to depletion. We found that the relationship between production and well orientation is consistently observed, regardless of the amount of proppant used. An economic analysis indicated that for wells of equal length, it is clearly beneficial to drill wells in the direction of Shmin. However, wells in the direction of Shmin are consistently shorter in length than off-azimuth wells, and it is generally more efficient to drill longer laterals on a given leasehold. Nevertheless, using the average oil price at the time the wells we studied were drilled, we find that the shorter wells in the on-azimuth direction have a significant economic uplift of several million dollars per well relative to the longer wells drilled in the off-azimuth direction.
Hydraulic fractures propagate in a plane perpendicular to the least principal stress (Hubbert and Willis, 1957) which normally means that hydraulic fractures propagate in vertical planes, normal to Shmin in areas characterized by strike-slip or normal faulting. When exploiting unconventional oil and gas reservoirs, it is common to drill horizontal wells with multiple hydraulic fracturing stages in the direction of Shmin. If the spacing between adjacent wells reflects the drainage area associated with the propped half-lengths of the hydraulic fractures of the wells, it would seem to result in optimal recovery. This said, in some areas wells are drilled in north-south or east-west directions regardless of the stress orientation to 1) optimally exploit available acreage with the highest number of wells and 2) take advantage of the fact that drilling longer wells decreases drilling and completion costs on a per foot basis.
In this paper we study the relationship between well orientation (relative to the stress field) in the Bakken play to assess its effect on production. The Bakken shale play is in the Williston Basin straddling a region of 200,000 square miles across western North Dakota, eastern Montana, Saskatchewan, and Manitoba. Unconventional oil production started in 2006 and peak oil production reached its maximum to date in 2019 with approximately 1.5 million barrels per day (EIA, 2020a). We have restricted this study to wells drilled in the Middle Bakken formation to avoid intermingling data from the less productive Three Forks.
Multi-fractured horizontal wells (MFHWs) have enabled commercial production from low-permeability oil reservoirs but oil recoveries remain exceedingly small using the primary recovery scheme. As a result, operators have investigated the use of solvent (gas) injection schemes, such as huff-n-puff (HNP), to improve oil recovery. Laboratory experiments simulating the HNP process have been proposed to allow the investigation of recovery mechanisms, and for use in simulating HNP pilots; however, these experiments typically 1) fail to represent field conditions properly and 2) require long test times when performed on intact core plug samples. The primary objectives of this proof-of-concept study are to 1) design and implement a new experimental procedure that better reproduces HNP schemes in MFHWs and 2) use the results to explore the controls on enhanced hydrocarbon recovery in tight reservoirs.
A liquid/relative permeameter, previously developed for measuring single/two-phase gas (hydrocarbons/non-hydrocarbons) and liquid (oil, brine) flow in tight rocks, has been modified to perform core-based HNP experiments. The experimental procedure involves: 1) artificially fracturing a reservoir core plug sample under differential biaxial stress conditions to simulate an induced hydraulic fracture, 2) saturating the fractured core plug sample with oil, 3) measuring stress-dependent fracture permeability with oil under loading and unloading conditions, 4) implementing multiple HNP cycles (gas injection, soaking and production). For 4), oil and gas production is measured for each step, and oil/gas compositions are measured after selected steps. Compositional numerical simulation is used to 1) optimize the experimental design prior to the experiments and 2) history-match each cycle after the experiments, enabling fundamental controlling mechanisms to be explored.
A low-porosity (2.8%), low-permeability [slip-corrected (N2) gas permeability: 1.25·10-4 md; 900 psi effective stress] Duvernay shale core plug sample was chosen for analysis, after fracturing and saturation with de-waxed (dead) formation oil. Fractured core plug (oil) permeability exhibited significant hysteresis between loading and unloading cycles. Six HNP cycles were performed with CO2 using an injection pressure of about 1300 psi, and typical cycle lengths of 1 hour for injection and soaking, and 4 hours for production. The six HNP cycles were implemented in only 28 hours (2 cycles were abbreviated), with maximum oil recovery < 50%. As expected, the magnitude of incremental oil recovery decreased after the first 2 cycles. The data were successfully history-matched with a numerical simulator.
Previous HNP experimental approaches may be classified as either ‘flow-through-matrix’ (gas injection into an intact core plug sample) or ‘flow-around-matrix’ (gas flow around an intact core plug sample) – the former tests require exceedingly long test times and are usually performed on higher permeability samples, while the latter tests result in small test times but exceedingly high oil recoveries due to unrealistic experimental conditions. The experimental method proposed herein endeavors to reproduce field conditions by conveying the gas through a fracture within the core plug sample subjected to confining stress, and fracture area controlling gas exposure to the sample. The experimental conditions are therefore more realistic, yielding more meaningful/reasonable test results in a shorter time frame.