In the early days of the oil industry, saline water or brine frequently was produced from a well along with oil, and as the oil-production rate declined, the water-production rate often would increase. This water typically was disposed of by dumping it into nearby streams or rivers. In the 1920s, the practice began of reinjecting the produced water into porous and permeable subsurface formations, including the reservoir interval from which the oil and water originally had come. By the 1930s, reinjection of produced water had become a common oilfield practice. Reinjection of water was first done systematically in the Bradford oil field of Pennsylvania, U.S.A. There, the initial "circle-flood" approach was replaced by a "line flood," in which two rows of producing wells were staggered on both sides of an equally spaced row of water-injection wells. In the 1920s, besides the line flood, a "five-spot" well layout was used (so named because its pattern is like that of the five spots on ...
Before computer modeling was common, the 3D aspects of a waterflood evaluation were simplified so that the technical problem could be treated as either a 2D-areal problem or a 2D-vertical problem. To simplify 3D to 2D areal, either the reservoir must be assumed to be vertically a thin and homogeneous rock interval (hence having no gravity considerations) or one of the published techniques to handle the vertical heterogeneity and expected gravity effects within the context of a 2D-areal calculation must be used. The primary areal considerations for a waterflood involve the choices of the pattern style (see Figure 1) and the well spacing. Maximizing the ultimate oil recovery and economic return from waterflooding requires making many pattern- and spacing-related decisions when secondary recovery is evaluated. This has been particularly true for onshore oil fields in the US in which a significant number of wells were drilled for primary production.
San Andres and Clearfork are two carbonate reservoir intervals that are present over a considerable area of the Permian Basin in west Texas. These reservoirs (e.g., Wasson, Slaughter, Seminole) contain several billion bbl of approximately 30 API oil. They are very-layered, heterogeneous carbonates and dolomites that have large variation in permeability from layer to layer. Interestingly, because of the complex hydrocarbon-accumulation history of this basin, much of this area has an underlying interval that contains residual oil saturation. Most of these reservoirs were discovered in the late 1930s and the 1940s.
Thermal EOR projects are technically and economically challenging projects. Improving the geological understanding and implementing these geological concepts into the static model were key to increase the robustness of, not only the geological model but also of the dynamic simulation.
The initial believe was that fine grained and mm scale laminated sediments act as vertical baffles for the steam distribution. The fine grained sands were low in permeability and the lamination were further reducing the vertical permeability. Grain size had the main impact on permeability and grain size was correlated with V-shale. Then, V-shale was used as a proxy for grain size and was integrated into a V-shale base porosity-permeability transformation.
After modeling the baffles explicitly, it was shown that against the initial belief, the main control on fluid flow was not a patchy baffle distribution. Instead the reservoir was overall reduced in vertical permeability. A lager impact had the V-shale base poro-perm transform, predicting an order of magnitude permeability range for a given porosity. Reducing the impact of the facies also reduced overall the uncertainty and improved the predictive power of the models. This in turn, helped to take development decisions with much higher confidence.
There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased - Consistency - Transparency - Reliability A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the "Petroleum Reserves Definitions." Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the "Petroleum Resources Classification System and Definitions." These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current "Petroleum Resources Management System," globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, "Modernization of Oil and Gas Reporting," published 31 December 2008. SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters: - Estimation of Petroleum Resources Using Deterministic Procedures (Chap.
Ahmadian, Mohsen (Advanced Energy Consortium) | LaBrecque, Douglas (Multi-Phase Technologies, LLC) | Liu, Qing Huo (Department of Electrical and Computer Engineering, Duke University) | Slack, William (FRx Inc.) | Brigham, Russell (Multi-Phase Technologies, LLC) | Fang, Yuan (Department of Electrical and Computer Engineering, Duke University) | Banks, Kevin (Inversion Technologies, Inc.) | Hu, Yunyun (Department of Electrical and Computer Engineering, Duke University) | Wang, Dezhi (Department of Electrical and Computer Engineering, Duke University) | Zhang, Runren (Department of Electrical and Computer Engineering, Duke University)
In April 2017, the Advanced Energy Consortium (AEC) successfully completed data collection for a proofof-concept demonstration of remote mapping of hydraulically fractured networks using electromagnetic (EM) proppant additives and a variety of EM tools and configurations. This field-pilot demonstration was conducted at the Devine Test Site, located approximately 50 miles southwest of San Antonio, Texas, and managed by the Bureau of Economic Geology (Bureau) at The University of Texas at Austin. The objective of the ongoing integrated research program is to develop a remote EMimaging technique for hydraulically fractured networks in order to obtain a higher-resolution image of proppant distribution (lateral/vertical extent and azimuth), which current technologies, such as microseismic, do not allow. The current study is a more in-depth followup to a series of shallow field tests that the AEC conducted in 2015 near Clemson University in South Carolina. This paper details the special aspects of the Devine Test Site that make it a unique asset for benchmarking EMbased hydraulic-fracture mapping tools and models. Results from the Devine Test Site demonstrate that a measurable and noticeable EM anomaly was detectable with both time-domain and frequency-domain induced polarization methods. EMinversion results were consistent with analysis of surface tiltmeter results but diverged significantly from passive seismic responses obtained during the hydraulic-fracturing process. The site will be cored at multiple locations over the next few months, after which accuracy of models and methods will be validated. Future opportunities for collaboration on this highly validated benchmarked site are discussed.
The Piceance Basin is located in western Colorado and covers an area of about 7,100 square miles1. A spoon-shaped basin, sediments reach a maximum depth of about 20,000 feet near the central portion, and encompass rocks ranging in age from Tertiary to Precambian. The basin is bounded by outcrops on the east, west and south, and by uplifts that separate it on the north from the Sand Wash Basin and on the northwest from the Uinta Basin. There are massive tertiary intrusives – laccoliths and volcanics – on the southeastern portion of the basin that have elevated the heat flow there and a massive basaltic flow extended west across a portion of the central basin to form the caprock of the Grand Mesa area. Figure 1 is a geologic map of the Piceance Basin in western Colorado1.
Oil and gas exploration in the Piceance Basin dates to the early 1900’s, with the discovery of the Rangely field in the northwest portion of the basin. With the exception of Rangely and a few other small fields, the basin is dominated by wells that produce natural gas. Oil and gas production from the Piceance Basin Mancos was first established in the Rangely field area, as well2. To date, about 30,000 wells have been drilled and completed in the basin, and the vast majority of those that are active, about 15,000 wells3, are producing from the Upper Cretaceous Williams Fork formation sands of the Mesaverde Group, in the central portion of the basin
Mancos Exploration to Date
Gas production was established from the Mancos B sand along the western flank of the basin, an area known as the Douglas Creek Arch, that separates the Piceance and Uintah basins, near the Colorado-Utah state line. The Mancos B sand is a sandy interval in the upper portion of the massively thick Mancos Group shale. In May 2001, WPX Energy began gas production from the lower portion of the Mancos shale in the central portion of the basin, in its vertical Vassar Heath RMV 229-27 well, at Section 27-T6S-R94W, in the Rulison Field.
To date, about 120 Mancos shale oil and gas wells have been drilled, completed and placed into production, not including the aforementioned Mancos B sand wells located along the Douglas Creek Arch and the wells in the Rangely field area. About 56 of these wells are vertical completions, and about 64 are horizontal completions. Figure 2 shows the total production from these wells, along with the Nymex price of natural gas. Note that exploration for Mancos shale gas wells began around the time that Nymex natural gas prices began to decline, and that since gas prices reached a low in early 2016, Mancos development has been limited to a few wells per year.
InSAR (Interferometric Synthetic Aperture Radar) is a technology used to measure changes in surface elevation between successive passes of orbiting satellites. These changes can be used to understand imbalances in the subsurface between fluid withdrawal and injection, as well as near-surface ruptures caused by failure of well integrity.
Satellites have recorded SAR data since the 1990s, and the data have become increasingly higher resolution and more frequently acquired. Combined with faster algorithms and processing chains for interferometry, this has enabled detection of smaller and faster changes at the surface. This in turn has caused a step-change in the usefulness of the data and the interpretations. The result is the ability to depend on the data to monitor the effects of production and injection processes almost continuously.
We review several cases to demonstrate the value of rapid revisit, high resolution InSAR. The first is the giant Belridge field in the San Joaquin valley, California, historically the poster child for this application. The diatomite reservoir rock has 60% porosity and is fluid supported. When equilibrium between injection to production is not maintained, the volume changes in the reservoir cause the ground surface to move up or down by amounts detectable with InSAR enabling a feedback loop for injection optimization. The field also has many wells with compromised wellbore integrity that can provide a pathway for reservoir fluids to move upwards towards the ground surface. When water, oil, or steam move out of the reservoir and into the overburden, a potential precursor can be detected provided InSAR is configured carefully. In a second case, InSAR also provides visualizations of ground level changes over gas fields and gas storage fields. At the Groningen gas field in the Netherlands, long term InSAR time series measurements of elevation changes are used to constrain models about compaction and reactivation of buried faults. Parts of the field that are used for seasonal gas storage and charging/discharging cycles can also be effectively monitored.
Measurement of surface deformation by high resolution, fast revisit, optimized InSAR provides an insight into the reservoir and the efficiency of its management. It also provides an early warning of potential problems that, if not corrected, may result in harm to the environment. These step changes in quantity and quality of available InSAR data mean that the remaining barrier to being used for actionable insights is in the widespread inverse modeling of the surface data to sub-surface mass flows.
Some key challenges in thermal heavy oil recovery include how to monitor steam flood effectiveness and cap-rock integrity. Kuwait Oil Company acquired baseline 3D VSP surveys in January 2016 as geophysical surveillance projects for a steam flood pilot. This paper presents a technical approach of 3D VSP acquisition design, data processing, seismic inversion, quantitative interpretation and its application for the monitoring of steam movement.
Applying pressured steam to a reservoir can lead to damage of overlying cap-rock and could cause energy leakage through fractures. The technique of baseline 3D VSP and future time-lapsed 4D VSP are designed to image steam flood movement within the reservoirs. The possible applications of 3D/4D VSP technology include imaging the steam chamber size of a 30-day steam cycle, reservoir characterization and investigating integrity of the sealing cap shale.
Extensive planning and immaculate execution of the 3D VSP operations resulted in timely completion of survey acquisitions with high quality data. Because of the optimized acquisition parameters, the frequencies attained in these surveys were more than 30% higher than previously achieved in this same area. Extensive modeling enabled innovative customization of the acquisition design, optimized parallel processing, and interpretation techniques have allowed for a time effective acquisition-to-results turnaround that may affect the second cycle of the steam injection program. Resulting analysis on processed data clearly indicate the steam flow shape and direction. These significant results are providing important input for development decisions.
The reduction of the bin size from high fold and tight source / receiver distribution proven to be an effective and high quality method for imaging shallow geological target reservoirs. The resulting high frequencies obtained allowed for better vertical and spatial resolution, which enabled steam chamber size estimation and study of cap-rock integrity.