Enhanced Oil Recovery Programs Research Articles

Pilot Lessons: Chesapeake’s Shale EOR Program Stalls But Still Offers Bold Vision

Before global oil prices turned south earlier this year in swift and historic fashion, Oklahoma City­based Chesapeake Energy was gearing up to build a new gas­compression station in the Eagle Ford Shale of Texas. The multimillion­dollar facility was to be the workhorse of the company’s first attempt at cyclic­gas injection, an enhanced oil recovery (EOR) method more commonly called huff ’n’ puff (HnP). Instead, the heavy equipment sits idle and the blueprints of the EOR program remain on the shelf as the operator restructures a debt load of more than $7 billion under a court­supervised bankruptcy process. But despite the uncertainty of Chesapeake’s future - or about when US crude prices will rise to levels that justify EOR operations - the company’s plan for a pilot and subsequent full­scale development in the Eagle Ford is noteworthy in that it would have represented the most ambitious attempt made yet to revive production from a tight­oil play. “Why would we want to do that? We wanted to do it because we can recover more oil without additional drilling,” said Dave Mohrbacher, a reservoir engineering advisor at Chesapeake and the company’s project manager of what was at one point a 40­person technical team. Mohrbacher presented a technical paper (SPE 200415) about the team’s efforts to lay the groundwork for a large­scale HnP program during the virtual SPE Improved Oil Recovery Conference held in late August. The adopted workflow calls for a relatively large pilot fol­lowed by the conversion of hundreds of wells within 2 to 3 years. Since 2016, Chesapeake has joined many others in the shale sector in paying close attention to a few small patches of ranch land in south Texas where EOG Resources announced that it had proven cyclic­gas injection was not only technically feasible, but a profitable way to increase recovery rates in tight­oil wells. The Houston­based EOG demonstrated that, under the right conditions, injecting gas back into shale reservoirs can cause the tiny droplets of oil still trapped inside to swell up. This mobilizes the residual oil by making it less viscous and sticky. EOG’s success story gave hope to shale producers across North America that the recovery rates of 5-10% of the original oil in place could be elevated to 7-17% by periodically soaking tight-oil reservoirs with miscible natural gas. Go Big, Go Fast Mohrbacher told industry colleagues that Chesapeake made the investment in its EOR program after confirming for itself through analysis and laboratory work that the reported gains of 10-40% in ultimate oil recovery via HnP were valid. Chesapeake was also motivated, he said, to achieve scale at a “more aggressive” pace than its predecessors because of its large position of maturing wells.

Reservoir property changes during CO2–brine flow-through experiments in tight sandstone: Implications for CO2 enhanced oil recovery in the Triassic Chang 7 Member tight sandstone, Ordos Basin, China

The effects of supercritical CO2 (ScCO2) on reservoir property changes of the Chang 7 Member tight sandstones of the Yanchang Formation, Ordos Basin, China, were investigated using CO2–brine flow-through experiments, in conjunction with detailed rock and fluid characterization (pre- and post-experiment) using X-ray diffraction mineral analysis, 3D computed tomography scanning, high-resolution scanning electron microscopy, and inductively coupled plasma–atomic emission spectrophotometry. An in situ 3D model was developed to define porosity–mineral evolution. Experiments on three contrasting samples show that minerals such as potassium (K) feldspar, albite, and calcite are variably dissolved during CO2–brine–mineral interactions. The dissolution, migration, and re-precipitation of clay minerals are common and are characterized by the dissolution of chlorite and the re-precipitation of kaolinite, calcium montmorillonite, and sodium montmorillonite. The original chlorite–kaolinite framework of the host rocks was destroyed. Precipitated and re-migrated clay particles (e.g., kaolinites and smectites) that were released by the dissolution accumulated in pore throats, resulting in changes to the pore system and in the physical properties of the host rocks. Physical property change pathways vary among the studied samples, with porosity being reduced by 4.5% and 12.8% or increased by 13.7% by the end of the experiments. Permeability reduction was 33.3%–81.2% and is positively correlated to host rock clay mineral content. The influence of the type and content of clay minerals on porosity requires further evaluation. The findings of the study have implications for the large-scale injection of CO2 into reservoirs during enhanced oil recovery programs and for carbon capture, utilization, and storage programs.

Preliminary Assessment of 22Cr and 15Cr Materials Selection for CO2 Enhanced Oil Recovery Program

Enhanced Oil Recovery (EOR) program to increase oil production from mature fields are now being implemented in Indonesia amid concern over the continuous decrease of oil production level. The mature fields and EOR process have the tendency to carry relatively high impurities components (CO2, H2S, chloride ions) that results in early corrosion occurrence, creating damages in the subsurface equipment (wellhead, tubing, Xmas tree, etc). In Java area with 0.09 TSCF potential gas reserves, 49.3 MMSTB oil and + 23% CO2 content, such amount of CO2 gas and possibility of H2S and chloride from the reservoir will require a higher grade material than the conventional carbon steel. This paper discuss the preliminary materials selection process in the program plan based on the existing condition. The material selection based on the evaluation of closest field data, literature review as a comparison, material, and fluid analysis test. Duplex 22Cr-15 Cr materials are the main study in the paper as the candidate for the tubing material in high CO2, high H2S and chloride environment. The polarization result in 27°C and 50°C showed that the chrome 22 %Cr material had pitting tendency in chloride ion 25,000 ppm, while at high temperature (80 °C) the pitting tendency shifted to 5,000 ppm of chloride ion.

Oman Champions EOR in the Middle East

Oman EOR Although famous for its abundant oil fields, generations of production in the Middle East is putting sharper focus on ultimate recovery from these fields. The issue is particularly pressing for Oman. Output in the country’s maturing oil fields peaked in the 1990s and Petroleum Development Oman (PDO), the national oil company, spearheaded the implementation of enhanced oil recovery (EOR) techniques with its first trials in the late 1980s. For Oman, EOR remains a major strategic option in its challenge to increase recovery and to meet long-term production requirements. Substantial efforts have been directed at investigating cost-effective ways in which production levels from existing fields can both be sustained and increased. Oman’s first EOR program was completed in 1989 and led to progress in experience gained and reduction in technical and cost uncertainties. Oman has seen considerable investment in a range of EOR technologies to produce heavy oil, and a host of other countries in the Middle East and India have been encouraged by Oman’s success. Between 2001 and 2007, Oman’s oil production fell by 27%, but by 2009, due mostly to EOR projects, oil production had increased by 17%. In a region where national oil companies essentially control all the hydrocarbon resources, Oman’s partnership between national and international oil companies stands out, also because it has been an important driving force behind the country’s EOR rollout. The growth in use of EOR techniques has increased the cost of Oman’s oil production but also has boosted output by 180,000 BOPD to 200,000 BOPD. Total Oman production is 940,000 BOPD. “In comparison with primary oil extraction, which sometimes costs only USD 4-5 per barrel, EOR techniques come at an expense of USD 10-12 per barrel,” said Salim bin Nasser Al-Aufi, undersecretary of the Ministry of Oil and Gas in Oman. The EOR techniques that Oman has used include chemical EOR as well as thermal and miscible gas injection. The choice of EOR technology is based on the reservoir depth and oil viscosity. PDO’s Experience PDO, which produces more than 80% of Oman’s oil production, commissioned its first EOR project in 2004, and expects that EOR will contribute to 25% of total liquids production by 2020. “We have had to move into a significant program of EOR technologies. We are the only company in the world that has thermal, miscible, and polymer chemical-injection recovery mechanisms within the same concession, all of which are in full-scale implementation,” said Raoul Restucci, managing director of PDO.

Carbon Capture: Harnessing Carbon Dioxide in the Middle East

Carbon Capture The migration to ultra-mature production and concern about rising greenhouse gas emissions mean that the implementation of carbon capture and storage projects are coming into sharper focus than ever before in the Middle East. Capturing carbon dioxide (CO2) and using it in enhanced oil recovery (EOR) is one strategy being widely adopted. Studies showing the region having one of the world’s highest per capita environmental footprints have led governments to look for ways to improve their rankings in greenhouse gas emissions. So far, Oman is the only country in the region to have launched EOR programs on a large commercial, rather than pilot, scale in a bid to stem and reverse years of declining crude production. In Abu Dhabi, tertiary gas injection has been under way for decades at the Total-operated Abu Al Bukhoosh field with great success. As production in the region matures, more countries are expected to implement EOR programs. The application of CO2 EOR provides two advantages for companies in the Middle East. It allows natural gas that would otherwise be used for injection into oil fields for secondary recovery to be freed up to meet domestic requirements, such as power generation and industrial use, or to limit the costly import of liquefied natural gas. Moreover, it helps limit emissions in the region.

An experimental study of CO2–brine–rock interaction at in situ pressure–temperature reservoir conditions

A detailed investigation of CO2–brine–rock interactions, through a core flooding laboratory experiment, was carried out under simulated reservoir conditions (100°C and 24MPa). Changes in the ionic chemistry of the outlet solution, combined with core scanning electron microscopy (SEM) and bulk-rock X-ray diffraction (XRD) analysis of the core pre- and post-experiment reveal new insights into CO2–brine–rock interactions. Minerals such as potassium (K) feldspar, albite, calcite, and ankerite are variably dissolved after the experiments. Calcite is the mineral most affected by dissolution, followed by ankerite, whereas dissolution of feldspar minerals is minimal. Small amounts of kaolinite and solid phases were generated as a result of the experiment. The solid phases are mainly comprised of C, O, Na, Cl, Al, and Si, and are presumed to be the transitional products in the formation of carbonate minerals. The very low fluid penetration rate in the experiment resulted in significantly reduced contact area between the acidic CO2 fluid and minerals in the cores, resulting in low rates of feldspar dissolution. Core permeability decreased substantially throughout the experiment, although core porosity remained unchanged. The permeability reduction is the result of precipitation of new mineral phases (e.g., kaolinite and solid phases), and potentially also the presence of clay particles released by the dissolution of carbonate cement, which have then been transported in the fluid flow path and accumulated at pore throats. The results provide new insights into CO2 trapping mechanisms in depleted oil and gas reservoirs, and into the potential formation damage that may result from massive injections of CO2 into reservoirs during enhanced oil recovery programs.

Hydrochemical-isotopic tendencies to define hydraulic mobility of formation water at the Samaria-Sitio Grande oil field, Mexico

The chemical (major elements) and isotopic ( 2H, 3H, 13C, 18O) composition of formation water is presented for the Sitio Grande oilfield, SE-Mexico, extracted from 28 production wells from the carbonate reservoir at a depth between 3585 and 4545 m.b.s.l. The linear δ 18O/δD-trend explains the formation of reservoir water as part of three subsequent stages: a) the evaporation of marine water at the surface, causing enrichment of both, δ 18O and δD-values, b) a reversal trend with decreasing δ 18O-and δD-ratios by the extreme evaporation of brines and, c) the subsequent mixing with isotopically depleted meteoric water. A SW-NE directed flow direction of deep groundwater systems is indicated by parallel-oriented isoline trends of stable isotope ratios and conservative elements, supported by the dominance of parallel directed microfractures and extensional faults, and by tracer test results. The arrival of artificial tritium, three years after tracer injection in the well SG-85, reflects a) the importance of long-term monitoring of tracer tests, and b) an estimated flow velocity of 2.2×10 −5 m/s. As the arrival of the tracer was detected exclusively in three production wells towards the SW of the injection site, lateral migration of groundwater occurs mainly along defined, channel-like conducts with a narrow dispersion angle of 39 °. Surface water, injected as part of an enhanced oil recovery program, was not detected in the production zone by chemical and isotopic methods. This fact is not a proof for lacking hydraulic conductivity, as the large reservoir size and the termination of the injection program in 1996 could have caused a complete dilution of the injected fluids. Restricted vertical flow movement between reservoir layers and insignificant temperature-dependent reaction processes is indicated by the heterogeneous distribution of δ 18O-and Cl-values throughout the groundwater column of most reservoir zones. Little influence of water-rock interaction, such as Ca-Mg exchange processes between formation water and host rock is reflected by the heterogeneous abundance of calcium in the liquid phase in both, dolomite-free and dolomitized carbonate host rock layers.

Tomographic Imaging as a Tool for Reservoir Surveillance and Developmental Geology: ABSTRACT

Tomographic image reconstruction techniques are being successfully extended for use in high resolution imaging of hydrocarbon reservoirs. Important applications of this technology include monitoring the movement of fluids in enhanced oil recovery (EOR) projects and analysis of reservoir structure, lithology, and mechanics. Typically, data is acquired between boreholes (cross-borehole tomography) or between borehole and surface (tomographic vertical seismic profile (VSP) and inverted VSP). By recording multiple components of the wave field, shear, and compressional wave velocity, tomograms can be reconstructed. From these images, additional tomograms of various elastic moduli of the reservoir rock can also be reconstructed, including bulk modulus (incompressibility), shear modulus, and Poisson's ratio. These tomograms carry information about lateral and vertical variations in reservoir lithology, fluid content, pressure, and temperature. Attention is now being focused on the interpretation of tomograms and the relationship between rock properties and geophysical measurements. The successful application of this technology to reservoir surveillance should result in improved field development and more efficient EOR programs.

Petroleum

The French enhanced oil recovery program illustrates the important criteria in university-industry research cooperation. A review of the buildup of industry and university collaboration on this research finds that, after eight years, 35 laboratories are involved, the science of colloids and microemulsions has advanced to a level of international distinction, and some large-scale experiments have proved promising. Close relations must be established in order for industry and the universities to both benefit. The collaborative structure should be loose enough to allow laboratories a high degree of freedom, but selective enough to drive the research toward industry's shorter term goal.

Some Aspects of the Potential Application of Surfactants or CO2 as EOR Processes in North Sea Reservoirs

Summary This paper reviews some aspects of the quantitative assessment of two types of enhanced oil recovery (EOR) processes and their potential application to North Sea reservoirs. Calculations are described that were undertaken for a simplified conceptual reservoir model with properties akin to those of the Forties field. Possible initial conditions for EOR operation resulting from various stages of waterflooding are evaluated. The results of EOR assessment calculations using advanced three-dimensional chemical flood and compositional simulators are presented, for both a low-tension aqueous surfactant presented, for both a low-tension aqueous surfactant process and for CO2 displacement in association process and for CO2 displacement in association with a chase water drive. Introduction Development of oil reservoirs in the North Sea is now approaching the stage when the production rate is equal to the annual consumption of about 80 MMtons within the U.K. There are 26 fields where production is already occurring or development is in production is already occurring or development is in progress. The locations of the principal fields are progress. The locations of the principal fields are illustrated in Fig. 1. From the outset it was recognized that secondary recovery should be initiated in the early stages of primary production. This is exemplified by the introduction of water injection in most fields and gas reinjection in some fields as part of the current development plans. Using these methods, the overall oil recovery is expected to be at least 1,400 MMtons, equivalent to 18 years' consumption. The U.K. Dept. of Energy estimates, that the possible recoverable reserves from these fields may be as high as 2,600 MMtons. The remaining unrecovered oil in place after conventional depletion is expected to be about 60 % of the original (i.e., between 2,100 and 3,900 MMtons), which represents a very substantial target for EOR. If the development of s successful EOR process allowed recovery of 10 % or more of the residual oil after waterflooding, the U.K.'s period of self-sufficiency would be extended by several years, with substantial benefit to the probable shortfall in the U.K. energy position in the late 1990's. position in the late 1990's.The U.K. Dept. of Energy has funded an initial study program to determine the research and development in EOR that would be needed for the particular conditions of North Sea reservoirs. This particular conditions of North Sea reservoirs. This program was intended to (1) investigate the program was intended to (1) investigate the applicability of those EOR processes seen as having the best potential and (2) undertake calculations aimed at evaluating the process technology. The ability to predict EOR performance under real reservoir predict EOR performance under real reservoir conditions was considered a key issue. The studies have been undertaken at AEE Winfrith with three teams respectively concerned with the design of high- pressure displacement experiments in long cores, evaluation of mathematical modeling techniques, and quantitative assessment of EOR displacement under various conceptual reservoir conditions. In addition to this conceptual study, a number of more basic research projects have begun at several universities, and the petroleum companies in the U.K. have been encouraged to increase their EOR programs in a collaborative manner. programs in a collaborative manner.This paper highlights some aspects of the assessment studies undertaken at Winfrith and draws attention to some of the features of the supply of EOR materials. JPT P. 1617

Role of U.S. Government in Promoting Enhanced Oil-Recovery Techniques

This paper describes the role of the U.S. government in promoting enhanced oil-recovery technology. Today, 21 major, multiyear, cost-shared enhanced oil-recovery contracts exist with industry. The goal of the federal program is to increase production by 900,000 B/D by 1985 and to add 15 billion bbl of oil to proved reserves. Introduction When one considers that more than 50% of the crude oil used in the U.S. is supplied by foreign countries, there is little doubt that increasing this nation's ability to produce oil is important. One near-term solution to this problem of dependence on foreign oil is to augment domestic supplies by applying enhanced oil recovery (EOR) to known domestic oil deposits. The targets for EOR application are the known 290 billion bbl of normal gravity oil, the more than 100 billion bbl of heavy oil, and the more than 30 billion bbl of bitumen in tar sand deposits (Table 1). The federal role in petroleum-production research and development (R and D) was historically of low profile because of the many R and D laboratories and efforts of major oil companies. For many years the USBM has conducted a modest in-house R and D effort at its energy research centers in Morgantown, WV; Bartlesville, OK; Laramie, WY; and San Francisco, CA. In fiscal year 1974, a moderate increase in funding permitted USBM to enter into cost-shared contracts with industry for EOR field demonstrations. The EOR program then was transferred from USBM to U. S . ERDA when it was formed Jan. 19, 1975, and to DOE when it was formed Oct. 1, 1977. The EOR program in DOE now has grown to funding of $46.1 million program in DOE now has grown to funding of $46.1 million in fiscal year 1978. There are currently 21 major cost-shared contracts with industry, at a total cost of $159 million. Additional supporting research is conducted at energy research centers, national laboratories, and many universities. To understand the role of government when using EOR technology is to understand the goals, plans, and current status of the DOE program for EOR. EOR Goals A primary objective of the DOE program is to stimulate the improvement of recovery efficiency from the presently estimated level of 32% of the original oil in place to presently estimated level of 32% of the original oil in place to a level of 35 to 38%. * With the estimated original oil in place exceeding 400 billion bbl, this somewhat small place exceeding 400 billion bbl, this somewhat small increase in percentage of oil recovery would be a substantial amount of additional oil. It could increase our proved reserves as of 1976 by one-third to more than one-half. The initial goal for increased incremental production by 1985 was so at USBM as a result of information generated from the federal Project Independence Blueprint analysis in 1972. It was estimated that, with favorable economics and an aggressive R and D program, EOR could provide a daily production increment of about 1.5 million bbl by 1985. The estimate was broken down further into about 500,000 bbl daily from normal industry commercialization and about 1 million bbl daily from the impact of the suggested R and D program. Those essentially were the goals adopted by ERDA when the EOR program was transferred in Jan. 1975. program was transferred in Jan. 1975. JPT P. 1086