The development of a wired composite tubing enables the continuous acquisition and transmission of petrophysical and drilling dynamics data during all phases of a drilling operation. This capability results in logging passes for each bit trip throughout the life of the well. The operator can then correlate and compare the data in real-time to better understand the borehole stability. This paper presents two case studies that illustrate the value of real-time time-lapse logging to a drilling operation.
The intervention of copper electrical conductors in Advanced Compisote Coil Tubing (ACCT) allows data to be transmitted at 156 kilobytes per second (kbps) between the downhole components and the surface system. This uninterrupted communication enables the operator to receive all of the data, all of the time, regardless of the drilling activities currently underway.
A major advantage of this system is the ability to monitor the petrophysical environment in real time, regardless of the drilling activity. Borehole stability is routinely monitored using downhole pressure and tension measurements in conjunction with surface injector weight. When combined with the petrophysical data, the borehole stability data can help identify, prevent, and cure fractures and permeable sands responsible for poor borehole stability.
The abundance of data needed for time-lapse logs is acquired through hole-cleaning trips to the shoe or surface. Although this process is time consuming, it does have an advantage. It provides multiple measurements after drilling logging passes (MAD) of the drilled hole section. Over time, the data tells a petrophysical story in real time about what is happening to the formational environment and borehole stability. Recently this type of logging has been referred to as "time-lapse logging" or "4D logging." Tabanou et al.1 and Bratton et al.2,3 have already showed that this type of logging is possible in conventional pipe-conveyed drilling, with only a few MAD passes over the same openhole section.
On a recent test well drilled near Galveston, Texas, more than thirty trips were made over the openhole section, below the casing window. The number of wiper trips made was considerably more than pipe-conveyed drilling would have required. In pipe-conveyed drilling, only a few good data passes are made over the same depth interval. In most cases, it is in recorded mode, or pseudo real time, and is time consuming to acquire. However, in a wired composite system, the time-lapse log is always in real time.
Two case studies from the test well have shown that MAD passes help improve borehole stability and petrophysical analysis in real-time:
Time-lapse logging of mud invasion in sands.
Identifying initiation and propagation of fractures in shale beds.
Overview of BHA Components
The system consists of an Advanced Composite Coil Tubing (ACCT) connected to a bottomhole assembly (BHA). The BHA is broken down into three or four sections. The fourth section consists of the openhole tractor, which is not required when gravity drilling. The bottom section of the BHA consists of the 3D steering tool, near-bit survey sensor, and motor. The middle section contains the measurement while drilling (MWD) sensors, the lower circulating sub, lower tension weight-on-bit sub, and the pressure sub. The top section consists of the upper circulating sub, tension sub, an electronic disconnect device, and downhole computer. The top of this section contains a voltage control unit and a drop-ball disconnect sub (Fig. 1). The openhole tractor is normally placed between the middle and upper section.
For the purpose of this paper, the pertinent parts related to time-lapse logging, the composite coil, resistivity tool, and pressure sub are covered in detail.
Seawater injection is a common practice for maintenance of reservoir pressure. A compact seawater deoxygenation system using regenerated nitrogen gas was introduced for offshore facilities in 1992. The original systems were based on a serpentine tube co-current mixing system. Due to the requirements of floating facilities to meet smaller footprint and weight, and to meet motion criteria in floating facilities, the third-generation system employs static mixers and a simplified control strategy. Based on experience from recent installations in offshore Thailand and Norway, troubleshooting guidelines are presented for operating turndown and debottlenecking scenarios.
Floating production systems requiring waterflood for reservoir maintenance are increasing. The use of a fuel gas stripping or vacuum tower require vessels with a vertical height often in excess of 40 feet. The tall tower height can introduce wave motion problems by having a high center of gravity. In addition, excessive tower height limits the placement of the waterflood system on the platform. A regenerative nitrogen stripping system utilizing static mixers and compact separator towers is able to overcome these obstacles.
The deoxygenation system discussed in this paper is based on contacting purified nitrogen stripping gas to remove dissolved oxygen from seawater. There are two main configurations of this process, the co-current system and the counter-current system. As the name indicates, the co-current system introduces nitrogen stripping gas with the flow of the seawater, and the counter-current system contacts the nitrogen stream against the flow of seawater.
The first generation unit utilized a co-current nitrogen flow with serpentine tubes to provide the mixing zone. These tubes were unobstructed, constant diameter tubes. The regeneration system used in this unit is the basis for the regeneration system used in successive units.
The second generation unit utilized a counter-current nitrogen flow with structured packing to provide the mixing zone. This unit was in response the general acceptance of vacuum tower deaerators and fuel gas stripping towers in industry. This unit utilized a similar configuration and control system to those systems with the exception that they used an inert stripping gas. This unit used a tower configuration generally about 10 feet less in height than a comparable vacuum tower. This led to the "compact" designation. A typical second generation system is shown in Figure 1 of the appendix.
The third generation system uses a co-current flow but employs static mixers to provide the mixing zone. This unit was developed to minimize unit height. In the second generation unit, vacuum towers, and fuel gas stripping towers all utilize towers with seam-to-seam heights often in excess of 30 feet. While the second generation unit considerably shortened this height, the possible advantages of using a system with a shorter overall height seemed numerous. Shorter overall height increases the possible locations the unit can be placed on a deck, especially helpful in a retrofit or if the production facility was not designed with seawater flood in mind in the beginning.
All systems use the same regeneration principle to purify the nitrogen stripping gas. The regeneration system consists of a preheater, gas-gas exchanger and a catalyst bed. A schematic of a typical third generation system is shown in Figure 2 of the appendix.
Geostatistics has entered a new age. Until few years ago, geostatistics could still be considered a leading-edge technology, developed and applied by a handful of specialists. Today, geostatistics is routinely applied to most of the reservoir characterization projects worldwide, providing the ‘quantitative geology' support needed in the reservoir simulation phase.
This paper describes how a geostatistical model can be built by integrating all the information generated in the individual disciplines, namely Geophysics, Petrophysics, Sedimentology, Stratigraphy and basic Reservoir Engineering. This approach guarantees the internal consistency of the reservoir study and provides a robust model to be upscaled in the forward simulation phase. The information contained in the 3D geological model can also be averaged and exported to a conventional mapping algorithm, thus providing a consistent set of traditional 2D maps of reservoir properties (Net to Gross, net sand, porosity, permeability).
A case study is presented, relevant to a Venezuelan oil and gas condensate field. The geostatistical model uses almost 400 wells and includes a stratigraphic section almost 3000 feet thick, with 60 productive sands and about 500 reservoirs. In this field, where a conventional map-based approach would have been a long and cumbersome job, the complete geostatistical model has been built and input to the simulator in less than 6 months. In such a context, geostatistics represented a fast and efficient tool for the integrated study.
Reservoir geologists became familiar with geostatistics starting at the end of the eighties, when several key papers1,2,3,4 demonstrated the potential of this technique when applied to petroleum reservoirs. However, for some years, geostatistics remained a sophisticated technology, accessible only to specialists. The theoretical development was driven by the quest for new algorithms, while less importance was given to the integration of the method within the routine work process of reservoir studies.
In recent years, however, it became evident to most geoscientists that geostatistics, or stochastic modeling, not only could provide better distributions of the geological parameters, but also has a tremendous potential for integrating data coming from different sources5. In particular, general geological knowledge (lithological and depositional models), geophysics and structural geology, petrophysics and basic reservoir engineering can provide useful inputs to the geostatistical model, which in turn become the real heart of the modeling process.
The possibility of integrating data coming from different sources and relevant to different support volume (scale), makes stochastic modeling the most powerful technique currently available for reservoir characterization. When such integration is achieved, we could talk about geologically oriented geostatistics.
This paper discusses the practical issues related to the use of geologically oriented geostatistics for geological modeling, as well as the results that have been obtained in the integrated study of the Zapatos-Mata R field (Eastern province, Venezuela).
Conoco's journey towards sustainability began in earnest about 2 years ago as an "incremental" effort to bring increased awareness of environmental and community responsibility to existing operations. Since then however, the company has evolved to a much richer understanding of sustainable development and its potential. Sustainable development is now considered a strategic framework for long-term business success with the potential to shape the company's direction and is the foundation for Conoco's vision of achieving sustainable business growth. Committing to financial excellence, environmental stewardship and broad, ongoing contributions to social development earns Conoco its license to operate and allows us to embrace new, value creating opportunities by leveraging our capabilities to bring sustainable solutions to our customers and stakeholders. In short, our commitment to sustainable development is seen as a fundamental prerequisite for Conoco's survival and success in the new century.
Like many companies that have embraced the concept of sustainable development, Conoco is now embarking on the challenge of translating that vision of economic, environmental and social sustainability into the reality of tangible value creation and sustainable growth. Strategic sustainability integration represents a shift in mindset away from traditional regulatory compliance, risk abatement, and cost control into the realm of opportunity identification. The purpose of this paper is to discuss Conoco's experience with strategic sustainability integration in its operations from around the world. Examples will describe community development efforts in Nigeria, the positive environmental impact of a natural gas project in Syria, as well as an integrated approach to extra-heavy oil development the environmentally sensitive Orinoco Oil Belt of Venezuela. These and other efforts represent the beginning of Conoco's journey towards strategic sustainability and total economic, social, and environmental value creation.
Sustainable development has become something of "darling" concept in the international energy industry over the past decade. In business' Triple Bottom Line interpretation of the 1987 Brundtland Commission definition of sustainable development - development that meet the needs of the present without compromising the ability of future generations to meet their own needs1 - many companies have been drawn to the concept by the siren song of the "yes and" proposition. Yes, society can have economic growth AND environmental health AND social progress. Our maturing understanding of the complex interdependency of these three legs of the sustainability platform supports the conclusion that this integration is not only possible but must be achieved to ensure a healthy standard of living now and for future generations.
Like many companies (and communities, NGOs, and governments) that have embraced the concept of sustainable development, Conoco is now embarking on the challenge of translating the vision of economic, environmental and social sustainability into the reality of tangible value creation. Strategic sustainability integration represents a shift in mindset away from traditional reasoning of regulatory compliance and cost control and away from the perception of environmental management and community relations as "add-on", cost-center components of project management. Rather the reward for sustainability thinking is the ability to capture the full value creation potential of social and environmental integration through the complete business life-cycle from opportunity identification, through decision-making, to project design and implementation. The purpose of this paper is describe Conoco's emerging and evolving process for strategic sustainability integration and to review some of our early and ongoing sustainability "experiments" in Orinoco Oil Belt of Venezuela, the steppes of Syria, and onshore Nigeria.
The Spraberry and Chicontepec fields are both giant oil fields contained within areally extensive, low porosity and low permeability submarine fan reservoirs. Each field has a gross interval of approximately 1,000-1,500 feet (300-450 m) with multiple reservoirs less than 10,000 feet (3,000 m) deep. Sand-prone intervals are laterally extensive and can be correlated regionally, but do have localized channeling. Both fields produce from solution-gas drive.
The Spraberry Trend Field, located in the Midland Basin of West Texas, was discovered in 1948. The field is estimated to contain over 10 billion barrels of original oil in place in a series of stacked Permian-age reservoirs covering over 2,500 square miles (6,475 sq. km). Cumulative production from the Spraberry is approximately 850 million barrels of oil and 3 trillion cubic feet of gas or approximately 8% of the original oil in place.
The Chicontepec Field, located in the Sierra Madre Oriental foothills in east-central Mexico, was first drilled in 1931. The field is estimated to contain 140 billion barrels of original oil in place and 35 trillion cubic feet of associated gas in a series of stacked Late Paleocene to Eocene-age reservoirs covering approximately 1,440 square miles (3,731 sq. km). Cumulative production from the Chicontepec Field is just over 140 million barrels of oil-equivalent or 0.1% of the original hydrocarbons in place.
However, the fields do differ significantly in their development history. Over 18,000 wells have produced some oil and gas from the Spraberry (over 10,000 currently producing) as compared to less than 1,000 in Chicontepec. Managing drilling costs, fracturing technology and controlling production costs along with economies of scale have allowed the Spraberry, once known as the world's largest uneconomic field, to be developed. Developing the Chicontepec field using similar methods would add significant reserves and production volumes for Mexico.
As we all know, finding new giant accumulations of oil and gas through exploration, especially in areas close to markets and existing infrastructure, is becoming increasingly difficult. An alternative is to look at previously discovered fields in these "mature" areas that are underdeveloped because of their historically low margin economics. Often through the use of new technology and by creative cost-cutting methods significant new production and reserves can be developed to more quickly meet consumer demand even without higher commodity prices.
This paper is a high-level comparison of two such fields; discussing the reservoir properties which have caused them to be deemed "uneconomic" and contrasting the development histories to suggest significant new reserves can be economically produced near-term from one that is underdeveloped.
The two fields are the Spraberry Trend Field located in the Midland Basin in West Texas and the Chicontepec Field located in east-central Mexico (Fig. 1). Both are located in mature producing regions where numerous other fields, including fields with significantly less original hydrocarbon in place, but with better reservoirs, have produced millions of barrels of oil and billions of cubic feet of gas.
This paper describes the technical and legal problems have had in the design and construction of several projects in the oil and gas industry in Mexico and propose a methodology in order to avoid that.
Traditionally the people in charge of the projects have been people with a lot of experience in different areas of the company but the knowledge in legal and technical aspects of the projects is limited. These last two aspects are the key in the solution of the common problems.
The proposed methodology is based on the experience through 18 years in the design and construction of several oil and gas installations and it is complemented with the analysis of legal and technical regulations.
Traditionally the design and construction projects are taken for a single person who is in charge of all aspects of the project since conceptual engineering until the tests and start up of the plants this way to do the projects brings a lot problems due to a bottleneck in the definitions of the main aspects of the projects which depend on the leader of the project who has a lot of experience in several aspects of the technical area or administrative area so normally the leader can solve the problems related with his experience but normally there are a lot of aspects that require definition in time and form for the correct development of the project and the background of the leader is not enough to solve them and unfortunately the main team do not have the knowledge and experience to solve them so the problems will accumulate until someone take the decision in order to continue with the project (Fig. 1).
This traditional way to do the projects has a lot of opportunity areas such as:
Bottleneck in taking decisions
Delaying of engineering works
Delaying in construction program
Increase in engineering costs
Increase in construction costs
Deviation of original objectives
Additional projects for solution
Increase in total cost of the project
Deviations from the mid and long term plans
Legal problems for the people
Life Cycle of the Project
The different steps of the project involve several disciplines since needs detection until site remediation (Fig. 2) each one has particular importance in according with the objectives of the department involved but at the end the main responsibilities fall over the engineering and construction department due to this department must understand the planning objectives and must to know the strength and weakness of the operation and maintenance department in order to give the best solution for the project. If there is some misunderstand this can cause problems on the project execution and break all the planning programs. In order to avoid that is necessary to adopt a new way to do the projects and one of the main changes is to do Performance Contract for each one of the people that will participate in the project, which let him to know and understand the objectives in the short. Middle and long term and in case of deviations be able to take the correct solutions in form and time in this way the relation inside the asset must be clear for the people (Fig. 3) The premises to get it are:
Working to Known Standards
It is proposed a simple methodology to secure the satisfactory ending of the project, it is divided in two main areas: Technical and legal.
As development of hydrocarbon reserves continues to move into deeper and more complex reservoir conditions, operators have found that conventional techniques for testing, perforating, and stimulating have not been capable of providing satisfactory results in the severe well conditions. Even if operationally satisfactory, they have been unable to meet the goals for cost efficiency.
This paper describes an experience in the Tropical Field, located in eastern Venezuela and operated by Repsol - YPF in which the reservoir is characterized by high-pressure reservoirs and complex geology due to faults and high-dip-angle formations. Repsol needed a method that would optimize well testing operations, improve safety, and cut costs without compromising the results of the operation; thus, a major change to traditional drill stem testing operations was needed. A technique, which would eliminate the need to kill the well to retrieve the guns and also provide the flexibility to test, evaluate, and fracture the well, was suggested. Instead of using a drilling rig or a work-over unit as in the standard drill- stem testing operation, the procedure would allow the operator to perform a rigless well test evaluation using optimum underbalanced conditions in favor of the reservoir.
Several alternatives were evaluated for perforating and testing the well. After thorough examination of all possibilities, snubbing- and coiled-tubing-conveyed perforating (CTCP) methods were selected as the most promising alternatives for achieving the objectives proposed at the beginning of the project. While coiled tubing had been used to perforate in other areas in Venezuela, coiled tubing combined with snubbing had not been used in Venezuela.
This paper will focus on the methods developed to satisfy the operational challenges, the results obtained with the use of the newly applied technologies, and how the technology was able to address the operator's needs as well as the difficult reservoir conditions. Instrumental in the success of the methodology was the combined use of super-deep penetration technology, state-of-the-art memory tools for depth correlation, real time data transmission, and the flexibility to perform several operations during a rigless well-test evaluation. This case history represents the first live-well intervention using snubbing and coiled-tubing perforating techniques performed successfully in eastern Venezuela.
The Tropical Field is located in east Venezuela approximately 28 miles from Maturin, capitol of Monagas state, in the North Monagas Area. This location is one of the most prolific production areas in the country. The reservoir is characterized by high-pressure and complex geology due to faults and high-dip-angle formations. The field is presently under development, and 4 wells have been drilled. Oil is produced from two locations - the San Juan Formation at approximately 13,890 feet and from the San Antonio Formation at approximately 14870 feet. The average total depths in the wells are 15,800 ft. and are slightly deviated. Thus, perforation techniques had to be capable of operating in complex geology due to faults and high-dip-angle formations.
Perforating Techniques used on Tropical Area.
During the exploratory stage of field development, tubing-conveyed perforating (TCP) was used since it offered the capability to perforate the well in an underbalanced condition. In the first wells, the TCP string included the DST string for evaluation. The wells still had to be killed, but underbalance was obtained. Then, rigless perforating systems were considered. The objective of this change was to optimize the cost involved during the well-testing evaluation operation, and at the same time, obtain the benefits that can be achieved from having the completion already in place and the capability to perforate without killing the well.
The technology applied at the beginning of the project was to perform TCP on coiled tubing; however in the well discussed in this case history, it also became necessary to use a snubbing unit to perform the gun runs because of the difficulties experienced in meeting operational requirements in the complex geology.
We present results of modeling studies of injection schemes with wells using new completions technology, and address how these are applied or envisaged for the fulfillment of field development strategies in offshore environments.
A common theme in offshore developments is the use of fewer wells to achieve the production targets of the field. In mature fields, the limited availability of well slots is a severe constraint. In new developments, the drive is towards fewer and smaller platform installations. In subsea developments, particularly in deepwater, the objective is minimization of wellheads. There are clear financial, environmental, and technical reasons for these trends.
The use of advanced completions technology to reduce well requirements has been widely practiced in relation to production wells. Commingling of production in layered, compartmentalized, and dispersed geological settings has been achieved with multilateral wells, and conventional wells with flow control technology.1-4 The application of this technology to injection problems has received relatively little attention.5-6
The objective of this study is to analyze a number of injection problems that arise from actual field development scenarios. Four cases will be presented. The first two concern achieving proper partitioning of injected water into multi-zone structures. The third case concerns achieving the total target injection rate and partitioning. The fourth case concerns the alternating injection of water and gas.
This is a deepwater field, being developed by subsea wells. The structure consists of two partially overlapping formations of high permeability (3-5 Darcies), separated by non-reservoir rock. There is no external drive mechanism in the reservoir (e.g. an aquifer). Injection is to commence at initial production. Vertical injectors completed in both formations are to be used. The lower formation has about 1.5 times the injectivity of the upper formation because of its larger effective thickness. The objective is to inject into the upper and lower formations with a split of about 45% and 55% respectively, in line with the estimated distribution of reserves. The operator plans to install fixed and/or variable flow control devices in the injectors. The study analyzed injection options with and without valves. As Figure 1 shows, when no valves are used, the water will spontaneously partition between the two zones in the ratio of about 20% into the upper zone and 80% into the lower zone at relatively low injection rates. As the injection rate increases, so does the frictional pressure loss and this changes the ratio between the upper and lower zones to about 35% and 65%. This is shown in Figure 2. Note, however, that the fracture gradient of the formation imposes a constraint on the injection rate. Figure 3 shows that the desired partitioning can be achieved when both formations are equipped with variable flow control valves. By adjusting the valve apertures, the partitioning of the injectivity can be adjusted as reservoir conditions evolve.
This example concerns injection into three zones simultaneously, prompted by the limited number of well slots available on the platform from which this reservoir is being developed. In comparison to the previous example, there is greater contrast in the reservoir properties among the three zones, so that the middle zone has the highest injectivity index. The operator has initiated a water injection program for pressure maintenance, using vertical dual-string injection wells (two tubing strings), with the short string injecting into Zone A and the long string into Zones B and C. With this configuration, the approximate partitioning in injectivity is 25%, 50%, and 25% (Figure 4).
Cost effective application of 3D before stack depth migration (BSDM) in the Lobo gas fields of south Texas has resulted in increased confidence in reservoir structure maps. Successful infill development locations have been drilled as a result of improved reconciliation of existing production with fault block area. The improved image has also led to the identification of new fault blocks and improved well locations. The case history of one area will illustrate how the program has generated value of over 40 times the initial investment in seismic processing. To date, nine depth migration projects have been completed.
The Lobo gas play comprises low permeable "tight" gas bearing sands encased in shales of late Paleocene-early Eocene age and trapped in a slump complex of rotated fault blocks1. The Lobo section ranges from 500-1200 ft (150-365 m) thick overlying the marine Midway shale and unconformably capped by lower Wilcox shales. The geopressured Lobo section ranges in depth from 5000-12000 ft (1525-3660 m). Due to the "tight" nature of the reservoir production is normally established after hydraulic fracturing of the well. Figure 1 shows the location of the Lobo fields adjacent to the Mexico-USA border in south Texas.
The first successful Lobo production was achieved in the Mexican Burgos Basin. This success led to drilling on the USA side of the border throughout the 1970's and to the rapid expansion of the play to an area covering approximately 1800 sq. miles (4660 sq. km) located in Webb and Zapata counties. Significant industry drilling occurred through the 1980's and early 1990's. In the mid 1990's increased 3D seismic acquisition led to a renewed phase of drilling activity. The ultimate recoverable gas of the Lobo play is estimated at 4.5 Tcf. Conoco, the leading acreage holder in the play, has drilled over 700 development wells since 1997 delivering an average production of approximately 600 mmcft/d during this period, equivalent to approximately one percent of USA gas demand.
As the play matures further there is a constant challenge to counter the creaming curve effect of falling reserves per well, drilling smaller structures, and increasing commercial risk as development drilling continues. To counter this trend the development teams are finding new ways to optimize the value of Conoco's assets by focusing on both reducing investment per well and maintaining drilling success and reserves per well. Several varied initiatives have been undertaken and are ongoing to address these challenges.
The primary geologic risk factors in the play are structure mapping and reservoir quality. Understanding reservoir pressure depletion is increasingly important as well spacing is reduced in the search for successful infill opportunities in densely drilled fault blocks. To successfully manage these risks and uncertainties more detailed reservoir management work is being conducted with particular emphasis on reservoir mapping and understanding production behavior. In some areas poor seismic image quality results in unacceptably high risk of accurately mapping the Lobo section. In many more areas fair seismic data quality results in mapping uncertainty due to questionable well ties and jump correlations of key reservoir packages and in failure to correctly identify reservoir level faulting. In the past, these issues were less important as many large structures were available for drilling. As the asset has matured, increasing attention to detailed reservoir characterization and seismic imaging is required to identify high quality development well locations.
Analyses suggest that carbon dioxide (CO2) can be injected into depleted gas reservoirs to enhance methane (CH4) recovery for periods on the order of 10 years, while simultaneously sequestering large amounts of CO2. Simulations applicable to the Rio Vista Gas Field in California show that mixing between CO2 and CH4 is slow relative to repressurization, and that vertical density stratification favors enhanced gas recovery.
Although the idea of injecting carbon dioxide (CO2) into depleted natural gas reservoirs for carbon sequestration with enhanced gas recovery (CSEGR) has been around for more than ten years1,2, and independent analyses have been carried out that suggest the feasibility of the process3,4, CSEGR has yet to be implemented commercially or even tested in the field. Among the reasons for this is concern about mixing of CO2 with native methane (CH4) gas and the corresponding degradation of value of the remaining natural gas. Our previous analysis of the physical processes involved in CSEGR suggested that mixing would be limited because of the high density and viscosity of CO2 relative to CH4.4 Furthermore, our simulations suggested that CSEGR could enhance gas production by a factor of five over 20 years relative to continued primary recovery over the same period for the large Rio Vista Gas Field in California. These prior simulations were done in idealized reservoirs using simple relations for gas mixture properties.
The purpose of this paper is to show additional and more detailed analyses that extend and amplify our prior findings to provide a broader scientific foundation for pilot testing and ultimate large scale deployment of CSEGR. These analyses include a discussion of physical properties of gas mixtures in the system CO2-CH4, and simulations of the effects of permeability heterogeneity and vertical stratification in a three-dimensional five-spot CSEGR scenario.
Background and Prior Work
As shown schematically in Figure 1 for a single power plant and gas reservoir, CSEGR is the injection of CO2 into depleted natural gas reservoirs for carbon sequestration with enhanced gas recovery. Because they have held large quantities of natural gas over geologic time scales, depleted gas reservoirs offer a proven integrity against gas escape and large available capacity for carbon sequestration, estimated at 140 GtC (Gigatonnes Carbon) worldwide5, and 10-25 GtC in the United States6. There do not seem to be any technical barriers to CO2 injection, although there are certainly costs associated with the injection of a highly corrosive gas such as CO27.
Despite the vast potential for carbon sequestration in depleted gas reservoirs, CSEGR has not been tested in the field due apparently to the high present cost of CO2 and infrastructure, concerns about excessive mixing, and the high primary recovery rates of many gas reservoirs8. These arguments notwithstanding, CSEGR may offer other benefits including pressure support in the reservoir to prevent subsidence and water intrusion. Furthermore, in the future companies may be paid to dispose of CO2 as a greenhouse gas as opposed to buying it as a commodity, thus reversing the economic barrier.
As for mixing, the injection of CO2 enhances gas recovery through both displacement, analogous to a water flood in oil recovery, and by repressurization of the remaining CH4. Repressurization of gas effectively concentrates the CH4 mass at distances far removed from the injection location without contamination by the injected gas. Furthermore, as discussed in our prior publication4 and below, the high density and viscosity of CO2 relative to CH4 can be exploited to avoid excessive mixing in the reservoir. In addition, the schematic of CSEGR for a coupled gas-fired power plant and gas reservoir shown in Figure 1 emphasizes that comanagement between the producing reservoir and the power plant may allow for greater acceptance of mixed CO2-CH4 gases as powerplant feedstock, in addition to allowing flexibility in gas production in response to fluctuating power demands.