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.
This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared with gas compression. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. Understanding of formation damage is a key theme in a waterflood project. An integrated multidisciplinary approach is required to determine an optimal design and strategy.
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.
This is the second of a three-part tutorial describing a workflow for evaluating unconventional resources including organic mudstones and tight siltstones. Part 1 reviewed the unique challenges and provided an overview of the proposed workflow (Newsham et al., 2019). Part 2 describes in detail the many components of the workflow and how they come together to determine the storage capacity of the reservoir. Part 3 links the petrophysical results to the production potential in terms of fractional flow and water cut and will present alternate cross-checks of the storage properties to validate the results.
As stated in Part 1, one of the most important functions that the petrophysicist provides is the estimation of accurate storage properties. However, when the authors survey the range of workflows used to estimate the storage capacity of these complex systems, we find a wide range of options. Solutions can vary from simple deterministic to more complex probabilistic approaches. Whatever the method, the objective should be the same: to provide consistent, portable hence reliable estimation of hydrocarbon storage capacity, also known as “Petrophysics CPR.” As mentioned in Part 1, estimation of hydrocarbon storage is more than just the calculation of porosity and water saturation. In this tutorial, we will describe a workflow that has been successfully used to evaluate thousands of wells in the Permian Basin with great consistency. The authors have nearly 100 wells with core data to calibrate the workflow. We will show examples of the workflow’s portability by highlighting examples from the Midland Basin, the Texas Delaware Basin and the New Mexico Delaware Basin. We will show how every property measured in core matches to log-based profiles using a combination of deterministic and the constrained simultaneous solution methods. The workflow also is found to be reliable in other basins throughout the world, however, the examples will be confined to the Permian Basins.
Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.
In recent years, the exploration and production of oil and gas from Bakken formation in Williston Basin have proceeded quickly due to the application of multi-stage fracturing technology in horizontal wells. Knowledge of the rock elastic moduli is important for the horizontal drilling and hydraulic fracturing. Although static moduli obtained by tri-axial compression test are accurate, the procedures are cost expensive and time consuming. Therefore, developing correlation to predict static moduli from dynamic moduli, which is calculated from sonic wave velocities, is meaningful in cutting cost and it makes the unconventional oil and gas exploration and production more efficient.
Literature review indicates such a correlation is not available for Bakken formation. This may be attributed to the extremely low success rate in Bakken core sample preparation and not enough published data to develop correlation to relate dynamic moduli to static moduli. This study measures and compares the moduli obtained from sonic wave velocity tests with deformation tests (tri-axial compression tests) for the samples taken from Bakken formation of Williston Basin, North Dakota, USA. The results show that the dynamic moduli of Bakken samples are considerably different from the static moduli measured by tri-axial compression tests. Correlations are developed based on the static and dynamic moduli of 117 Bakken core samples. The cores used in this study were taken from the core areas of Bakken formation in Williston Basin. Therefore, they are representatives of the Bakken reservoir rock. These correlations can be used to evaluate the uncertainty of Bakken formation elastic moduli estimated from the seismic and/or well log data and adjust to static moduli at a lower cost comparing with conducting static tests. The correlations are crucial to understand the rock geomechanical properties and forecast reservoir performance when no core sample is available for direct measurement of static moduli.
The recent slump in oil prices has resulted in new terminology: “drilled uncompleted wells,” often referred to as DUC wells by the industry. In 2013 and 2014, when oil prices were more than USD 100/bbl, rate of return (ROR) from most unconventional plays was in the range of 15 to 50%, depending on the quality of rock and the operator’s portfolio in the basin. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought on line for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells: fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). The paper also showcases case studies in which real-time observations made from wells have been used to validate predictions from forward-looking fracture and production models.
First, fracture hits commonly have been observed in all unconventional plays throughout the US, with effects on offset wells being mixed. Some fracture hits result in a positive uptick in production in offset wells, whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, and other responses. Understanding fracture hits and their influence on other wells is very critical to avoid any detrimental impacts or to leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on length of production history and parent-well-completion geometries in offset wells. Third, in basins where there are multiple producing horizons or formations, fracture-height growth and interference between adjacent formations can result in asymmetric fracture propagation toward depleted zones. The longer these wells completed in the same/adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluation of their impact on fracture geometries in DUC wells. Last, in areas with high-density drilling, a combination of longer production and fracturing stages with multiple perforation clusters per stage can leave very little oil available for the DUC well to produce.
Understanding reservoir-rock characteristics and the forces that mobilize oil in unconventional reservoirs is critical in designing oil-recovery schemes. Thus, we conducted laboratory experiments for three preserved Middle Bakken cores using centrifuge and nuclearmagnetic-resonance (NMR) instruments to understand oil-recovery mechanisms in the Bakken. Specifically, we measured capillary pressure, pore-size distribution (PSD), and oil and brine saturations and distributions.
A series of oil/brine-replacement experiments (drainage and imbibition) were conducted for the preserved cores using a high-speed centrifuge. T2 time distribution and 1D saturation-profile measurements were obtained using a 2-MHz NMR instrument before and after centrifuge experiments. Moreover, PSD was determined from mercury-intrusion capillary pressure (MICP) and nitrogen-gas-adsorption experiments. We conducted scanning-electron-microscope (SEM) imaging on polished cubical cores to determine pore shapes and mineralogy of pore walls using a field-emission SEM (FE-SEM).
Our measurements show that these three preserved Middle Bakken cores show mixed-wet characteristics. Water resides in smaller pores and oil resides in larger pores in all experiments. Using a low-salinity synthetic brine of 50,000 ppm to surround Bakken cores of much-higher salinity, we produced up to 6.33% [of pore volume (PV)] oil from two higher-porosity (approximately 8%) cores, and 10.72% (of PV) oil from one lower-porosity (approximately 2%) core in a spontaneous-imbibition (SI) experiment. Up to 6.62% (of PV) oil from the two higher-porosity cores and 11.23% (of PV) oil from the lower-porosity core were produced in a forced-imbibition (FI) experiment as well. These experiments indicate that molecular diffusion/capillary osmosis overrides the wettability effects in low-permeability Middle Bakken cores. The new observations regarding molecular diffusion/capillary osmosis have altered our classical notion of capillary imbibition in low-permeability reservoirs.
Saini, Dayanand (California State University, Bakersfield) | Wright, Jacob (California State University, Bakersfield) | Mantas, Megan (California State University, Bakersfield) | Gomes, Charles (California State University, Bakersfield)
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well’s cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California’s Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.
The Bakken was one of the first US shale basins in which fracturing techniques were applied to recover oil. The crude oil production in the Bakken surpassed the record set in December 2014, reaching a new high of 1.273 million bbl/day in early 2018. The treatment design has always been an essential part to maximize oil recovery from the reservoirs. There have been some papers reporting individual well studies and data analysis purely based on public databases, but very few provided a direct comparison of different treatments on several well pads in close proximity.
This paper studied the two popular fracture fluid systems, slickwater and hybrid treatment, at adjacent wells in the same area with the same operator and service provider in the Bakken. This method provides the most statistically reliable comparison by minimizing the possible contributions from all the other factors, like well reservoir property, completion design and operation execution. There were 10 slickwater jobs and 9 hybrid jobs on several pads within a 3-mile radius. Both treatment methods were applied on each pad during zipper fracturing. The hybrid jobs used friction reducers during the pad and moved on to crosslinked guar fluid when sand was pumped. For slickwater jobs, friction reducers were used through the entire treatment. Fracturing fluid usage, proppant intensity and pumping rate were compared, as well as the well production at 3, 6 and 12 months.
The production data showed that even with 28% less proppant pumped during the job, the wells treated with slickwater had significantly higher long-term production. In addition, by replacing the hybrid jobs, the chemical and equipment requirements onsite were also largely reduced. These direct comparison results can help future fracturing job designs to improve oil production in terms of fluid system, proppant intensity and pumping rate.