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Summary Magnetic resonance imaging (MRI) of core samples in laboratory experiments showed that CO2 storage in gas hydrates formed in porous rock resulted in the spontaneous production of methane with no associated water production. The exposure of methane hydrate in the pores to liquid CO2 resulted in methane production from the hydrate that suggested the exchange of methane molecules with CO2 molecules within the hydrate without the addition or subtraction of significant amounts of heat. Thermodynamic simulations based on Phase Field Theory were in agreement with these results and predicted similar methane production rates that were observed in several experiments. MRI-based 3D visualizations of the formation of hydrates in the porous rock and the methane production improved the interpretation of the experiments. The sequestration of an important greenhouse gas while simultaneously producing the freed natural gas offers access to the significant amounts of energy bound in natural gas hydrates and also offers an attractive potential for CO2 storage. The potential danger associated with catastrophic dissociation of hydrate structures in nature and the corresponding collapse of geological formations is reduced because of the increased thermodynamic stability of the CO2 hydrate relative to the natural gas hydrate. Introduction The replacement of methane in natural gas hydrates with CO2 presents an attractive scenario of providing a source of abundant natural gas while establishing a thermodynamically more stable hydrate accumulation. Natural gas hydrates represent an enormous potential energy source as the total energy corresponding to natural gas entrapped in hydrate reservoirs is estimated to be more than twice the energy of all known energy sources of coal, oil, and gas (Sloan 2003). Thermodynamic stability of the hydrate is sensitive to local temperature and pressure, but all components in the hydrate have to be in equilibrium with the surroundings if the hydrate is to be thermodynamically stable. Natural gas hydrate accumulations are therefore rarely in a state of complete stability in a strict thermodynamic sense. Typically, the hydrate associated with fine-grain sediments is trapped between low-permeability layers that keep the system in a state of very slow dynamics. One concern of hydrate dissociation, especially near the surface of either submarine or permafrost-associated deposits, is the potential for the release of methane to the water column or atmosphere. Methane represents an environmental concern because it is a more aggressive (~25 times) greenhouse gas than CO2. A more serious concern is related to the stability of these hydrate formations and its impact on the surrounding sediments. Changes in local conditions of temperature, pressure, or surrounding fluids can change the dynamics of the system and lead to catastrophic dissociation of the hydrates and consequent sediment instability. The Storegga mudslide in offshore Norway was created by several catastrophic hydrate dissociations. The largest of these was estimated to have occurred 7,000 years ago and was believed to have created a massive tsunami (Dawson et al. 1988). The replacement of natural gas hydrate with CO2 hydrate has the potential to increase the stability of hydrate-saturated sediments under near-surface conditions. Hydrocarbon exploitation in hydrate-bearing regions has the additional challenge to drilling operations of controlling heat production from drilling and its potential risk of local hydrate dissociation (Yakushev and Collett 1992). The molar volume of hydrate is 25-30% greater than the volume of liquid water under the same temperature-pressure conditions. Any production scenario for natural gas hydrate that involves significant dissociation of the hydrate (e.g., pressure depletion) has to account for the release of significant amounts of water that in turn affects the local mechanical stress on the reservoir formation. In the worst case, this would lead to local collapse of the surrounding formation. Natural gas production by CO2 exchange and sequestration benefits from the observation that there is little or no associated liquid water production during this process. Production of gas by hydrate dissociation can produce large volumes of associated water, and can create a significant environmental problem that would severely limit the economic potential. The conversion from methane hydrate to a CO2 hydrate is thermodynamically favorable in terms of free energy differences, and the phase transition is coupled to corresponding processes of mass and heat transport. The essential question is then if it is possible to actually convert methane hydrate as found in sediments to CO2 hydrate. Experiments that formed natural gas hydrates in porous sandstone core plugs used MRI to monitor the dynamics of hydrate formation and reformation. The paper emphasizes the experimental procedures developed to form the initial natural gas hydrates in sandstone pores and the subsequent exchange with CO2 while monitoring the dynamic process with 3D imaging on a sub millimetre scale. The in-situ imaging illustrates the production of methane from methane hydrate when exposed to liquid CO2 without any external heating.

A study was undertaken with the objective of evaluating the use of low concentrations of surfactant to improve oil recovery. Various concentrations of commercial surfactants were screened for long term stability at high temperature in seawater. Cloud points, precipitation, and the stability of surface tension were used as screening criteria. Spontaneous imbibition tests at ambient and reservoir temperatures were conducted using reservoir chalk plugs that were moderately water-wet. A selected surfactant, when added at low concentrations (100 to 500 parts per million of active surfactant) to the imbibition water reduced the residual oil saturation over imbibition tests conducted without surfactant. Acceleration of spontaneous imbibition was observed in tests that had improved oil recovery. Forced imbibition tests for viscous displacement were conducted by flow tests. Although low concentrations of surfactant did not lower oil-water interfacial tension below single digits, a reduction in residual oil saturation was obtained in the forced imbibition tests over tests without surfactant. Measurement of surfactant adsorption indicated that low adsorption at reservoir conditions could be obtained below the critical micelle concentration (CMC) of some surfactants. The combination of improved recovery with low adsorption suggests that the addition of surfactant to injected water may improve the economics of surfactant-enhanced water flooding under appropriate conditions. Introduction Surfactants have long been considered for improving oil recovery from oil reservoirs. Although many pilot tests and a few field tests have been conducted, the economics of surfactant injection have rarely been favorable. Most surfactant studies focused on the injection of a high concentration of surfactant to create ultralow interfacial tension between oil and water via microemulsions followed by a slug of polymer designed to mobilize the surfactant bank and oil. The front end cost of such a process was only favorable if residual oil saturations could be reduced to near zero, surfactant adsorption was not excessive, the sweep efficiency was excellent and oil prices were high. In contrast, consideration herein was given to improving the economics by a process that used only a dilute amount of surfactant to minimize adsorption and to recover only a portion of the residual oil. Published field tests1,2 show that it is possible to have an economic surfactant process at low surfactant concentrations. Others have examined in the laboratory, the possibility of dilute surfactant flooding for improving oil recovery3,4,5. This paper will focus on improvements observed in the displacement of oil in the laboratory and the approach to minimize surfactant losses. Description and Application of Equipment and Processes Preparation of Materials. Kansas outcrop chalk and field reservoir chalk were used in this study. Field reservoir plugs were extracted by alternation of toluene and methanol soaks until no hydrocarbon discoloration was observed (1–2 months). All plugs were one inch in diameter and up to 3.5 inches in length. The wett ability of the Kansas outcrop plugs was altered by aging under field crude oil at initial water saturation using established methods6 and then extracted like the field reservoir plugs. Spontaneous imbibition tests were used to establish a baseline measurement and to select moderately water-wet plugs for further testing. The field stock-tank crude oil was centrifuged to remove paraffins that were solid at near-ambient temperatures. N-decane of 99+% purity was used and filtered through a silica gel column before use. The brines were equilibrated with chalk material and filtered before use. Other fluids were used as purchased. Surfactants were commercially available products. They were diluted with synthetic North Sea water to desired concentrations before use. Preparation of Materials. Kansas outcrop chalk and field reservoir chalk were used in this study. Field reservoir plugs were extracted by alternation of toluene and methanol soaks until no hydrocarbon discoloration was observed (1–2 months). All plugs were one inch in diameter and up to 3.5 inches in length. The wett ability of the Kansas outcrop plugs was altered by aging under field crude oil at initial water saturation using established methods6 and then extracted like the field reservoir plugs. Spontaneous imbibition tests were used to establish a baseline measurement and to select moderately water-wet plugs for further testing. The field stock-tank crude oil was centrifuged to remove paraffins that were solid at near-ambient temperatures. N-decane of 99+% purity was used and filtered through a silica gel column before use. The brines were equilibrated with chalk material and filtered before use. Other fluids were used as purchased. Surfactants were commercially available products. They were diluted with synthetic North Sea water to desired concentrations before use.

Several laboratory CO2-foam experiments were performed in South Cowden Unit cores to select a suitable surfactant for possible CO2-foam application in the South Cowden Unit. Four surfactants Chaser CD-1045, Chaser CD-1050, Foamer NES-25 and Rhodapex CD-128 were evaluated for their foaming ability. Chaser CD-1045 and Rhodapex CD-128 were selected for further testing after an initial screening. These surfactants were tested in co-injection as well as Surfactant Alternating with Gas (SAG) processes at various frontal velocities. The resulting foams exhibited Selective Mobility Reduction (higher resistance factor in higher permeability zones) as well as shear-thinning behavior. While average resistance factor for the foam produced in four sections of a field core was higher for the co-injection of Chaser CD-1045 than Rhodapex CD-128, the later surfactant performed better in the SAG process as well as exhibiting lower adsorption in Baker Dolomite cores. While it is difficult to select Chaser CD-1045 over Rhodapex CD-128 based on laboratory data alone, economics and calculations might select one product over the other. Two adsorption tests performed with Chaser CD-1045 in presence of 250 ppm hydroxy ethyl cellulose as a sacrificial agent did not reduce adsorption of this surfactant. Introduction This study is a small part of a $20 MM project funded by the United States Department of Energy and the Working Interest Owners (WIO) of the South Cowden Unit. In this Class II DOE project horizontal wells have been drilled for CO2 flooding. However, as a contingency to improve sweep efficiency of CO2 in the horizontal injection wells, this study was initiated to screen four surfactants to identify the best candidate for possible CO2-foam application for mobility control in horizontal wells at the South Cowden Unit following CO2 flood. Four surfactants, Chaser CD-1045 and Chaser CD-1050 obtained from Chaser International Rhodapex CD-128 provided by Rhone-Poulenc and Foamer NES-25 obtained from Henkel Corporation, were evaluated. Since this was a comparative study, it would have been necessary to use identical cores to evaluate the foaming ability of the surfactants. However, due to a severe inhomogeneity of the South Cowden Unit cores, identical tests performed in a single field core would have been the next choice. Initial CO2-foam tests performed in a South Cowden Unit core showed that front end of the core would collapse within 2-3 core tests due to dissolution of softer parts of the core. To avoid this problem a short South Cowden Unit core was placed upstream of the test core. This provision extended the life of the test core so that all four surfactants could be tested in the same test core. The goal of these initial studies was to select the best two surfactants for further testing for selection of the best candidate for CO2-foam applications at the South Cowden Unit. The follow-up studies included evaluation of the effect of surfactant concentration, frontal velocity, comparisons of co-injection versus Surfactant Alternating with Gas (SAG) processes, and determination of surfactant adsorption in cores with no oil or cores at residual oil saturation. All surfactant solutions used in these studies were prepared in Synthetic South Cowden Unit Brine. Analysis of this brine is given in Table 1. CO2-Foam Test Setup and Flooding Procedure All CO2-foam flooding experiments were performed at the reservoir temperature of 98 F under 2000 psi of pressure. Figure 1 shows a schematic diagram for the setup used in evaluating the foaming ability of various surfactants Core 12A, a South Cowden Unit core used to rank the four surfactants in their foaming ability, was 1" in diameter and 4.84" in length. P. 81^

SPE Members Abstract The East Vacuum Grayburg San Andres Unit (EVGSAU) operated by Phillips Petroleum, is the site selected for a comprehensive evaluation of the use of foam for improving the sweep efficiency of a CO2 flood. The four-year project is jointly funded by the EVGSAU Working Interest Owners (WIO), the U.S. Department of Energy (DOE), and the State of New Mexico. The Petroleum Recovery Research Center (PRRC), a division of the New Mexico Institute of Mining and Technology (NMIMT), is providing laboratory and research support for the project. A Joint Project Advisory Team (JPAT) composed of technical representatives from numerous major oil companies, PRRC, and DOE provides input, review and guidance for the project. This paper is the second in a series of papers detailing various aspects of the CO2 Foam Field Verification Pilot test at EVGSAU. An earlier paper summarized the project plans and detailed the laboratory work leading to the selection of a surfactant for the field trial. This paper presents:an overview of the operating plan for the project,details of the foam injection schedule and design criteria, anda discussion of the data collection program and performance criteria to be used in evaluating successful application of foam for mobility control in the EVGSAU CO2 project. Specific items discussed in the foam injection design include the determination of surfactant volume and concentration, selection of the surfactant-alternating-gas (SAG) injection sequence for foam generation, field facilities, operations during foam injection, and contingency plans. An extensive data collection program for the project is discussed including production testing, injection well pressure and rate monitoring, injection profiles, production well logging, observation well logging program, and both gas and water phase tracer programs. Introduction The EVGSAU, located about 15 miles northwest of Hobbs in Lea County is the site of the first full-scale miscible carbon dioxide injection project in the state of New Mexico. CO2 injection at EVGSAU began in September, 1985. The CO2 project area covers 5000 acres developed using an 80-acre inverted nine-spot flood pattern. The total CO2 injection rate is about 30 MMcf/D. A water-alternating-gas (WAG) ratio of 2:1 (time basis) is used in the project, resulting in about one-third of the project area being on CO2 injection at any one time. In any given area, a WAG cycle consists of about four months of CO2 injection followed by eight months of water injection. This results in approximately 1.5 to 2% hydrocarbon pore volume (HCPV) CO2 injection and 3 to 4% HCPV brine injection per WAG cycle. The project is currently in the seventh WAG cycle. The tertiary oil response at EVGSAU to date has been very favorable. As shown in Figure 1, the waterflood decline established prior to CO2 injection has been arrested, and oil production has held approximately constant near the current 9000 BOPD Unit total for the past six years. P. 115^