The oil and gas production landscape in North America has seen a paradigm shift since the collapse in oil prices in 2014. Although prices remain challenging, several operators have managed to sustain the relatively long period of low margins through some aggressive approaches. This paper inspects changes in operating strategies and field development plans across all oil-rich basins in the US Rocky Mountain fields and how operators have used a combination of low oilfield service prices, high-graded well locations, and incremental fluid/proppant volumes to increase production.
The paper investigates the transformation in operating philosophies since 2014 in four oil-rich basins in the Rocky Mountain region—Williston, Denver-Julesburg (DJ), Uinta, and Powder River. The Bakken formation in the Williston basin represents one of the best-quality rocks in all of North America. However, high oil-price differentials and well costs have made it difficult for drilling to remain profitable. The core of the DJ basin (Wattenberg) has one of the lowest break-even prices in the region, and rig count continues to increase as operators start seeing signs of recovery in the market. The Uinta basin, although relatively small in size, has shown tremendous return potential in the form of multiple stacked pays and promising production results. The Powder River basin poses one of the toughest operational environments in the region owing to wildlife stipulations, harsh weather, and deeper targets.
High-graded well locations in the Bakken are limited to few fields, which limits the scope of expansion in the current oil price environment. The DJ basin is challenged with high-density well spacing; estimated ultimate recovery (EUR) per drilling spacing unit (DSU) continues to increase, but EUR per well has gone down by as much as 60%. In the Uinta basin, formations never known to be continuous in the Green River group have shown significant return potential. The Powder River basin has recently attracted large investments from major independent operators as they tackle drilling challenges associated with abrasive rocks and testing optimum lateral landing points.
Case studies show how operating strategies have changed with changes in oil prices. The Bakken and DJ basins are relatively mature, and as drilled-but-uncompleted (DUC) inventory continues to increase, depletion from existing wells and interference between fractures is impacting production from new wells. The Powder River basin is still in the exploratory phase, and operators are still working on reducing well-costs, optimizing fracturing-fluid/proppant volumes, and examining productivity of other target rocks. The Uinta basin is in the early phases of expansion, with many of the fields still being explored for scalability. Changes in production maps and completion trends provide a comprehensive understanding of how these variables have impacted oil output from the region since 2012.
Mogbolu, Emmanuel (The Shell Petroleum Development Company Nigeria Limited) | Agbor, Etta (The Shell Petroleum Development Company Nigeria Limited) | Ukeko, Onoriode (The Shell Petroleum Development Company Nigeria Limited) | Briggs, Tamunoseleipiri (The Shell Petroleum Development Company Nigeria Limited) | Ndukwe, Agwu (The Shell Petroleum Development Company Nigeria Limited)
The primary focus of a wells, reservoir and facilities management team is to guaranty shareholders value by improving production and optimize recovery. Several best practices abound in the industry to achieve this goal. Some screening criteria are used during integrated field reviews to benchmark identified opportunities and rank/select viable candidates for execution. This screening criteria includes: economic ranking, reserves, doability and regulatory policies. The resulting unconventional study allows for a better reservoir management plan.
This paper presents an integrated methodology utilized to restore oil production for a brown field via gaslift project. This was applied in the NAMUB Field case and the information obtained can be applied on other fields with similar scenarios.
In the case of NAMUB field, the estimation of the incremental oil resource volume was estimated using Material Balance models that are calibrated with pressure data and history matched. The field did not meet up with conventional screening criteria for Gaslift Project. This is due to technical, non-technical and economic reasons.
The field studied is composed of stacked reservoirs that have not had oil production for about ten years. Therefore, it was pertinent that a project had to be executed to restore/ carry out oil rim development. This was further made expedient due to the gas cap blowdown of the reservoirs. The continuous gas development impacted on the recovery of oil and further eroded oil resource volume. This integrated study comprised of Surface Engineering disciplines, Petroleum Engineering/ Geoscience disciplines, Economists and Business Planners.
The outcome of inter-reservoir communication studies and sensitivity analyses was integrated to manage uncertainties leading to robust outcomes. The results obtained were not benchmarked against any previous one, as this was a unique step out scenario the company had to deal with. The performance of the 5 wells will be monitored against actual production to validate the methods and processes adopted in this study.
The integrated approach used in the study across the diverse disciplines allowed for seamless delivery of the project.
Low temperature (60 and 100 °C) and long-term (6 months to 5 years) heating of pre-evacuated and sterilized shales and coals containing kerogen Types I (Mahogany Shale), II (Mowry Shale and New Albany Shale), and III (Springfield Coal and Wilcox Lignite) with low initial maturities (vitrinite reflectance Ro 0.39 to 0.62%) demonstrates that catalytically generated hydrocarbons may explain the occurrence of some non-biogenic natural gas plays where insufficient thermal maturity contradicts the conventional thermal cracking paradigm. Extrapolation of the observed rate of catalytic methanogenesis in the laboratory suggests that significant amounts of sedimentary organic carbon can be converted to relatively dry natural gas over tens of thousands of years in sedimentary basins at temperatures as low as 60 °C.
Our laboratory experiments utilized source rock chips sealed in gold and Pyrex® glass tubes in the presence of hydrogen-isotopically contrasting waters. Parallel heating experiments applied hydrostatic pressures from 0.1 to 300 MPa. Control experiments constrained the influence of pre-existing and residual methane in closed pores of rock chips that was unrelated to newly generated methane.
This study’s experimental methane yields at 60 and 100 °C are 5 to 11 orders of magnitude higher than the theoretically predicted yields from kinetic models of thermogenic methanogenesis, which strongly suggests a contribution of catalytic methanogenesis. Higher temperature, longer heating time, and lower hydrostatic pressure enhanced catalytic methanogenesis. No clear relationships were observed between kerogen type or total organic carbon content and methane yields via catalysis. Catalytic methanogenesis was strongest in Mowry Shale where methane yields at 60 °C amounted to ~2.5 μmol per gram of organic carbon after one year of hydrous heating at ambient pressure.
Future studies need to evaluate the possibility that clumped isotope characteristics of catalytically generated methane can diagnose the low-temperature regime of catalytic methanogenesis. Furthermore, testing of freshly cored anoxic rocks is needed to determine whether the use of archived, oxygen-exposed rocks in geochemical maturation/catalysis studies introduces artifacts in hydrocarbon yields.
The Green River, Utah holds the world's greatest oil shale resources. However, the hydrocarbon, which is namely kerogen, extraction from shales is limited due to environmental and technical challenges. In this study, we investigated the effectiveness of the combustion process for shale oil extraction. Samples collected from the Green River formation were first characterized by X-ray Diffraction (XRD) and Scanning Electron Microscopy (SEM). Then, series of dry combustion tests were conducted at different heating rates and wet combustion tests by water addition. The combustion efficiency was enhanced by mixing oil shale samples with an iron based catalyst. The effectiveness of dry, wet, and catalyst added combustion processes was examined by the thermal decomposition temperature of kerogen. Because the conventional oil shale extraction methods are pyrolysis (retorting) and steaming, the same experiments were conducted also under nitrogen injection to mimic retorting. It has been observed that the combustion process is a more efficient method for the extraction of kerogen from oil shale than the conventional techniques. The addition of water and catalyst to combustion has been found to lower the required temperature for kerogen decomposition for lower heating rate. This study provides insight for the optimization of the thermal methods for the kerogen extraction.
Openhole sand-control technique selection has been a topic of interest since the late 1990s and was discussed most comprehensively in SPE 85504 (Price-Smith et al. 2003), which proposed guidelines for selection between standalone screens (SASs), α/ß packing, and shunt-tube packing. Proposed guidelines were based on formation characteristics such as formation strength, particle-size distribution (PSD), mineralogy across the well path; risk factors involved in execution as well as reliability/longevity; and cost considerations. From a PSD standpoint, their guidelines were based on the criteria proposed earlier in SPE 39437 (Tiffin et al. 1998), whereas risk evaluation was based on the technologies available at that time. Since then, significant advancements were made in understanding sand-retention mechanisms and failure modes of SASs, and in technology development to extend the limits of openhole gravel packing. These combined with the field experience in the last decade certainly warrant re-examination of their guidelines, which is the objective of this paper.
In this paper, we begin with a critical review of the current sand-control technique-selection methodologies for openhole completions, including the way some of the risk factors are being evaluated to eliminate a given completion technique. On the basis of the technologies developed in the last decade, we propose a new approach for selecting sand-control technique, along with techniques/tools for proper evaluation of the risk factors. The proposed approach significantly extends the application limits of SASs and α/ß packing compared with what was proposed in SPE 85504 (Price-Smith et al. 2003).
Distributed acoustic sensing (DAS) is a novel technology that can take almost any fiber-optic installation and turn the fiberoptic cable into a large seismic array, which can provide enhanced imaging and monitor fluids and pressures in the reservoir. Two key marine borehole seismic field trials using fiberoptic DAS technology were recently executed. The first field trial was conducted by BP in a Trinidad Mahogany production well using standard fiber to pressure/temperature (P/T) sensors. The second field trial was conducted by Shell and was acquired simultaneously in two injector wells at the Mars Field, located in the deepwater Gulf of Mexico, with BP as a co-owner. Successful imaging results from the two trials demonstrate many potential applications of DAS technology.
Seismic imaging and time-lapse reservoir monitoring can give us critical information to guide placement of production and water flood injection wells in our high-value reservoirs. However, below salt and other complex overburden, surface or seabed seismic may not give us the required resolution of fine-scale reservoir architecture (Figure 1). Also, the signal-to-noise ratio (S/N) in time-lapse seismic is often poor due to two-way travel through salt.
However, permanent instrumentation of wells with large seismic arrays is not possible with today’s conventional technology. Can we use simple fiber-optic cables, already deployed in producing wells for downhole gauges or cabled in new wells, to perform high-resolution seismic imaging and monitoring of our reservoirs?
The concept is extremely attractive, and is implemented simply by deploying a special optical interrogator unit enabling the seismic distributed acoustic sensing (DAS) concept attached to optical fiber installed in a well. The energized fiber-optic cable then effectively transforms the entire length of the fiber into a large array of seismic sensors. With signals generated by surface seismic sources and received by multiple wells, data can be acquired to achieve an imaging and monitoring prize otherwise not possible (Mateeva et al., 2012; Li et al., 2013).
To achieve this vision as well as to evaluate the technology, marine field trials were executed. Here fiber-optic cables, originally deployed in production wells for pressure/temperature (P/T) measurements, were used to turn our wells into giant sensing antennas to image and monitor our reservoirs. Although the concept is simple and requires only an interrogator unit attached to the wellhead and a surface seismic energy source, many challenges exist to the successful implementation of the technique from both a data acquisition perspective and in handling the enormous quantities of VSP traces that are acquired.
The effects of two different types of pyrolysis on Iratì Formation oil shale core samples are examined. This work will parallel previous work done on oil shale from the Green River. Elbaharia (2012) demonstrated a new method of collecting velocities of oil shale samples as a function of temperature to derive elastic moduli and Thomsen parameters; the data presented here is an extension of this work applied to Iratì Formation oil shale. In many areas, such as the state of Saò Paulo, Brazil, most of the Iratì formation crops out according to Dyni (2006). Two cores from the same outcrop section were cored at a 45° angle to bedding orientation and were subjected to anhydrous and hydrous pyrolysis. Compressional and shear waveform data were collected during pyrolysis for velocity analysis. While the hydrous pyrolysis did prove to exhibit greater changes in the waveform data, accurate velocity determination was compromised due to high lateral and axial deformation in the samples during the experiment. This non-elastic deformation was on account of thermal expansion and contraction. Visual observations using the Computer Tomography (CT) scanner shows the differences in the two samples’ horizontal and lateral distortion and large scale fracture generation, while images from an Environmental Scanning Electron Microscope (ESEM) show micron scale fracturing and kerogen conversion to bitumen. We find that hydrous pyrolysis had a greater effect on the physical properties, fracture generation, and kerogen-to-bitumen conversion. We will present our results in the context of total organic carbon (TOC) and source rock analysis (SRA) before and after pyrolysis.
According to Nowacki (1981), oil shale is characterized as “A number of diverse fine-grained rocks [that] have been found to contain refractory organic material that can be refined into fuels.” To refine these rocks and produce fuels, they must be placed under high temperature and pressure conditions to convert the immature organic material (kerogen) into bitumen, and then to hydrocarbons, accelerating the natural maturation process. It is important to model changes in physical properties as a function of temperature. Elastic properties and Thomsen parameters are of interest for log calibration and seismic interpretation, and can be found by assuming samples are transversely isotropic (TI) based on Thomsen (1986).
Procyk, Alex (ConocoPhillips) | Gou, Xinjun (ConocoPhillips) | Marti, Srinagesh K. (ConocoPhillips) | Burton, Robert C (ConocoPhillips) | Knefel, Markus (GKD) | Dreschers, Daniel (GKD) | Wiegmann, Andreas (Math2Market) | Cheng, Liping (Math2Market) | Glatt, Erik (Math2Market)
Erosion of sand control screens in oil and gas wells can lead to catastrophic completion failures, substantial production losses and damage to downstream facilities. Screen erosion can be caused by a number of completion design and environmental factors. However, the dominant failure mechanism is production of small solids through the screen openings, leading to development of localized high-velocity hot spots in the screen filter media and subsequent failure of the media. The current work discusses a detailed screen erosion study conducted to evaluate screen flow parameters leading to erosion and to provide safe operating guidelines for wells completed using cased hole perforated frac-pack (CHFP) and cased hole perforated gravel-packed (CHGP) completions with premium wire-mesh sand control screens. The erosion study consisted of both experimental work to determine erosion damage in screen samples and computational fluid dynamic (CFD) simulations to help visualize particle flow paths through the metal-mesh sand control media and determine local flow velocities and erosion-induced wear patterns. The experimental erosion tests and CFD modeling were performed on a specific screen configuration used in a number of subsea gas wells subject to high velocity flow conditions and associated high screen erosion potential.
Open Hole Gravelpacks and Open Hole Stand-Alone Screen Completions are used in many high rate oil and gas wells. Selection criteria for determining the applicability of these alternative completion techniques tends to be company specific with proponents of Open Hole Gravelpacks claiming significantly better productivity and reliability than Open Hole Stand-Alone Screens. Review of laboratory and field data in this study shows these claims to be erroneous.
This paper presents results of well productivity studies from field and laboratory data comparing Open Hole Gravelpack and Open Hole Stand-Alone Screen flow performance. Key completion design and installation parameters driving performance for each completion type are identified and discussed. Field well life and reliability data are also reviewed to show that properly designed and installed open hole completions have reliability statistics similar to those seen in cased hole gravelpacks and frac-packs.
Design criteria using an integrated reservoir characterization, laboratory testing and field installation procedure are provided to allow better selection between Open Hole Gravelpacks and Open Hole Stand-Alone Screen completions.