scholarly journals CO2 Injection and Enhanced Oil Recovery in Ohio Oil Reservoirs—An Experimental Approach to Process Understanding

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6215
Author(s):  
Manoj Kumar Valluri ◽  
Jimin Zhou ◽  
Srikanta Mishra ◽  
Kishore Mohanty
Keyword(s):  
Oil Recovery ◽  
Power Plants ◽  
Oil And Gas ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Co2 Injection ◽  
Reservoir Properties ◽  
Industrial Facilities ◽  
Water Alternating Gas ◽  
Process Understanding

Process understanding of CO2 injection into a reservoir is a crucial step for planning a CO2 injection operation. CO2 injection was investigated for Ohio oil reservoirs which have access to abundant CO2 from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO2 under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO2 injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone.

Feasibility Investigation and Modeling Analysis of CO2 Sequestration in Arbuckle Formation Utilizing Salt Water Disposal Wells

2009 ◽  
Vol 131 (2) ◽  
Author(s):  
Jamal Daneshfar ◽  
Richard G. Hughes ◽  
Faruk Civan
Keyword(s):  
Co2 Sequestration ◽  
Power Plants ◽  
Oil And Gas ◽  
Chemical Interaction ◽  
Salt Water ◽  
Injection Pressure ◽  
Simulation Models ◽  
Co2 Production ◽  
Co2 Injection ◽  
Reservoir Properties

The rate of CO2 production in many states, primarily from coal-fired power plants, is such that it only takes a few years to fill up any depleted oil and gas reservoirs. In order to reduce the level of CO2 in the atmosphere and to minimize the cost of sequestration, the injection of CO2 into aquifers utilizing disposal wells has been targeted. In this paper, an analysis of one particular case, namely, the Arbuckle formation in Oklahoma, was carried out to demonstrate its feasibility for CO2 sequestration. First, a general review for CO2 sequestration into aquifers utilizing existing disposal wells is presented. The limiting criteria for CO2 sequestration in terms of the geology of the aquifer, lithology of the host rock, cost of operation, impact on reservoir properties, depth of the completed interval to maintain supercritical conditions for CO2, injection pressure and rate to minimize gravity segregation, mobility ratio to prevent viscous fingering, and chemical interaction of aqueous and solid phases are discussed. Then, the existence of residual oil in the aquifer and its effect on reaction chemistry concerning the potential CO2 sequestration applications in the Arbuckle formation are evaluated. This investigation was conducted by means of simulation of the prevailing processes. The cutoff points from dissolution to precipitation for each constituent in terms of different CO2 injection rates were obtained by utilizing the simulation models GEM-GHG and PHREEQC and were supported by a database of 150 disposal wells from which 25 wells were completed in the Arbuckle formation. We critically evaluate the current state of knowledge, identify areas needing research, and offer practical approaches for the evaluation of potential CO2 sequestration sites using commercial disposal wells.

Designing CO2 Transmission Pipelines Without Crack Arrestors

2010 ◽  
Author(s):  
Graeme G. King ◽  
Satish Kumar
Keyword(s):  
Wall Thickness ◽  
Carbon Capture ◽  
Power Plants ◽  
Oil And Gas ◽  
Cost Optimization ◽  
Operating Conditions ◽  
Operating Pressure ◽  
Design Work ◽  
Industrial Facilities ◽  
Pipeline Network

Masdar is developing several carbon capture projects from power plants, smelters, steel works, industrial facilities and oil and gas processing plants in Abu Dhabi in a phased series of projects. Captured CO2 will be transported in a new national CO2 pipeline network with a nominal capacity of 20×106 T/y to oil reservoirs where it will be injected for reservoir management and sequestration. Design of the pipeline network considered three primary factors in the selection of wall thickness and toughness, (a) steady and transient operating conditions, (b) prevention of longitudinal ductile fractures and (c) optimization of total project owning and operating costs. The paper explains how the three factors affect wall thickness and toughness. It sets out code requirements that must be satisfied when choosing wall thickness and gives details of how to calculate toughness to prevent propagation of long ductile fracture in CO2 pipelines. It then uses cost optimization to resolve contention between the different requirements and arrive at a safe and economical pipeline design. The design work selected a design pressure of 24.5 MPa, well above the critical point for CO2 and much higher than is normally seen in conventional oil and gas pipelines. Despite its high operating pressure, the proposed network will be one of the safest pipeline systems in the world today.

scholarly journals Chemistry of Reservoir Fluids in the Aspect of CO2 Injection for Selected Oil Reservoirs in Poland

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6456
Author(s):  
Ewa Knapik ◽  
Katarzyna Chruszcz-Lipska
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Oil Composition ◽  
Co2 Solubility ◽  
Geological Co2 Storage ◽  
Reservoir Conditions

Worldwide experiences related to geological CO2 storage show that the process of the injection of carbon dioxide into depleted oil reservoirs (CCS-EOR, Carbon Capture and Storage—Enhanced Oil Recovery) is highly profitable. The injection of CO2 will allow an increasing recovery factor (thus increasing CCS process profitability) and revitalize mature reservoirs, which may lead to oil spills due to pressure buildups. In Poland, such a solution has not yet been implemented in the industry. This work provides additional data for analysis of the possibility of the CCS-EOR method’s implementation for three potential clusters of Polish oil reservoirs located at a short distance one from another. The aim of the work was to examine the properties of reservoir fluids for these selected oil reservoirs in order to assure a better understanding of the physicochemical phenomena that accompany the gas injection process. The chemical composition of oils was determined by gas chromatography. All tested oils represent a medium black oil type with the density ranging from 795 to 843 g/L and the viscosity at 313 K, varying from 1.95 to 5.04 mm/s. The content of heavier components C25+ is up to 17 wt. %. CO2–oil MMP (Minimum Miscibility Pressure) was calculated in a CHEMCAD simulator using the Soave–Redlich–Kwong equation of state (SRK EoS). The oil composition was defined as a mixture of n-alkanes. Relatively low MMP values (ca. 8.3 MPa for all tested oils at 313 K) indicate a high potential of the EOR method, and make this geological CO2 storage form more attractive to the industry. For reservoir brines, the content of the main ions was experimentally measured and CO2 solubility under reservoir conditions was calculated. The reservoir brines showed a significant variation in properties with total dissolved solids contents varying from 17.5 to 378 g/L. CO2 solubility in brines depends on reservoir conditions and brine chemistry. The highest calculated CO2 solubility is 1.79 mol/kg, which suggest possible CO2 storage in aquifers.

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

2013 ◽  
Vol 16 (01) ◽  
pp. 60-71 ◽  
Author(s):  
Sixu Zheng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Saturation ◽  
Water Alternating Gas ◽  
Heavy Oil Reservoirs ◽  
Water Cut

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

scholarly journals MODEL-BASED OPTIMIZATION OF CYCLES OF CO2 WATER-ALTERNATING-GAS (CO2-WAG) INJECTION IN CARBONATE RESERVOIR

2022 ◽  
Vol 15 (4) ◽  
pp. 139-149
Author(s):  
F. G. A. Pereira ◽  
V. E. Botechia ◽  
D. J. Schiozer
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Co2 Production ◽  
Co2 Injection ◽  
Optimal Size ◽  
Control Variables ◽  
Limit Values ◽  
Water Alternating Gas ◽  
Production Wells ◽  
The Impact

Pre-salt reservoirs are among the most important discoveries in recent decades due to the large quantities of oil in them. However, high levels of uncertainties related to its large gas/CO2 production prompt a more complex gas/CO2 management, including the use of alternating water and gas/CO2 injection (WAG) as a recovery mechanism to increase oil recovery from the field. The purpose of this work is to develop a methodology to manage cycle sizes of the WAG/CO2, and analyze the impact of other variables related to the management of producing wells during the process. The methodology was applied to a benchmark synthetic reservoir model with pre-salt characteristics. We used five approaches to evaluate the optimum cycle size under study, also assessing the impact of the management of producing wells: (A) without closing producers due to gas-oil ratio (GOR) limit; (B) GOR limit fixed at a fixed value (1600 m³/m³) for all wells; (C) GOR limit optimized per well; (D) joint optimization between GOR limit values of producers and WAG cycles; and (E) optimization of the cycle size per injector well with an optimized GOR limit. The results showed that the optimum cycle size depends on the management of the producers. Leaving all production wells open until the end of the field's life (without closing based on the GOR limit) or controlling the wells in a more restricted manner (with closing based on the GOR limit), led to significant variation of the results (optimal size of the WAG/CO2 cycles). Our study, therefore, demonstrates that the optimum cycle size depends on other control variables and can change significantly due to these variables. This work presents a study that aimed to manage the WAG-CO2 injection cycle size by optimizing the life cycle control variables to obtain better economic performance within the premises already established, such as the total reinjection of gas/CO2 produced, also analyzing the impact of other variables (management of producing wells) along with the WAG-CO2 cycles.

scholarly journals Beyond Carbon Steel: Detecting Wellbore Shape and Cavities, and Cement Imperfections in Cased Wells

Energies ◽  
2019 ◽  
Vol 12 (21) ◽  
pp. 4211
Author(s):  
Timofey Eltsov ◽  
Tadeusz W. Patzek
Keyword(s):  
Magnetic Field ◽  
Carbon Steel ◽  
Oil Recovery ◽  
Magnetic Permeability ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Carbon Capture And Storage ◽  
Vertical Component ◽  
Co2 Injection ◽  
Gas Field

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.

Thermally Active Polymer To Improve Sweep Efficiency of Waterfloods: Simulation and Pilot Design Approaches

2012 ◽  
Vol 15 (01) ◽  
pp. 86-97 ◽  
Author(s):  
R.. Garmeh ◽  
M.. Izadi ◽  
M.. Salehi ◽  
J.L.. L. Romero ◽  
C.P.. P. Thomas ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Pilot Project ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Sensitivity Analyses ◽  
Chemical Components ◽  
Chemical Adsorption ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Thief Zone

Summary A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods. This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed. Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (Kv/Kh), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low Kv/Kh (&lt; 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high Kv/Kh and strong water segregation. The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.

Petroleum Reservoirs

1996 ◽  
Author(s):  
Craig M. Bethke
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Saline Water ◽  
Fluid Pressure ◽  
Petroleum Reservoirs ◽  
Hot Water ◽  
Reservoir Rock ◽  
Mineral Surfaces ◽  
Improved Oil Recovery ◽  
Mineral Scale

In efforts to increase and extend production from oil and gas fields, as well as to keep wells operational, petroleum engineers pump a wide variety of fluids into the subsurface. Fluids are injected into petroleum reservoirs for a number of purposes, including: • Waterflooding, where an available fresh or saline water is injected into the reservoir to displace oil toward producing wells. • Improved Oil Recovery (IOR), where a range of more exotic fluids such as steam (hot water), caustic solutions, carbon dioxide, foams, polymers, surfactants, and so on are injected to improve recovery beyond what might be obtained by waterflooding alone. • Near-well treatments, in which chemicals are injected into producing and sometimes injector wells, where they are intended to react with the reservoir rock. Well stimulation techniques such as acidization, for example, are intended to increase the formation's permeability. Alternatively, producing wells may receive “squeeze treatments” in which a mineral scale inhibitor is injected into the formation. In this case, the treatment is designed so that the inhibitor sorbs onto mineral surfaces, where it can gradually desorb into the formation water during production. • Pressure management, where fluid is injected into oil fields in order to maintain adequate fluid pressure in reservoir rocks. Calcium carbonate may precipitate as mineral scale, for example, if pressure is allowed to deteriorate, especially in fields where formation fluids are rich in Ca++ and HCO3- and CO2 fugacity is high. In each of these procedures, the injected fluid can be expected to be far from equilibrium with sediments and formation waters. As such, it is likely to react extensively once it enters the formation, causing some minerals to dissolve and others to precipitate. Hutcheon (1984) appropriately refers to this process as “artificial diagenesis,” drawing an analogy to the role of groundwater flow in the diagenesis of natural sediments (see Chapter 19). Further reaction is likely if the injected fluid breaks through to producing wells and mixes there with formation waters. There is considerable potential, therefore, for mineral scale, such as barium sulfate (see the next section), to form during these procedures.

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