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Texas
This paper was part of a student paper session included in the conference. The paper was included in the proceedings as paper STUDENT3. Abstract Surfactant enhanced aquifer remediation has become an acceptable remediation technology to remove groundwater contaminants such as petroleum hydrocarbons and chlorocarbons.There have been several recent field demonstrations of surfactant remediation where surfactants are used to significantly increase the solubility of the nonaqueous phase liquid (NAPLs) in water.The success of these tests was due to a unified approach using site characterization coupled with a laboratory screening followed by 3D modeling of the process for design and optimization purposes. Here we present the design aspects of the subsurface surfactant flood with the emphasis on the flow and transport modeling.The University of Texas numerical model UTCHEM was used for this purpose.UTCHEM is a three-dimensional, multiphase, multicomponent chemical compositional simulator capable of modeling NAPL migration and groundwater flow and transport in aquifers.Simulations are performed to determine test design variables. These include wellfield configuration and rates, duration of injection and composition of surfactant solution, and hydraulic control achievement using hydraulic control wells. We illustrate an approach to design and optimize surfactant-enhanced aquifer remediation processes in a systematic and efficient manner.To make the approach efficient, a framework that can distribute multiple numerical simulations on a cluster of processors has been successfully implemented. This framework integrates a chemical-enhanced numerical model, UTCHEM, an experimental design methodology, and a Monte Carlo algorithm with a robust global optimization search engine to identify the optimal combination under conditions of uncertainty. Introduction Surfactant flooding process has been used in petroleum industry for many years to enhance the oil recovery[1].During recent years, surfactant-enhanced aquifer remediation has become an acceptable remediation technology to remove groundwater contaminants such as petroleum hydrocarbons and chlorocarbons[2–5].There have been several recent field demonstrations of surfactant remediation where surfactants are used to significantly increase the solubility of phase liquid NAPLs in water[6–8].The success of these tests was due to a unified approach using site characterization coupled with a laboratory screening[9–12] followed by 3D modeling of the process for design and optimization purposes[13–15]. Here we present an innovative approach on the design and optimization aspects of subsurface surfactant flood by using a 3D modeling numerical simulator, UTCHEM.The approach was demonstrated by simulating the dense nonaqeous phase liquid (DNAPL) remediation in a shallow aquifer flushed with surfactant at Hill Air Force Base in Utah[15].
Abstract Hydraulic fracturing fluid systems are used to create the required fracture geometry and transport proppant into the fracture with a distribution that allows for the optimum performance of the well. Most systems currently use water-soluble polymers composed of guar or guar derivatives. Additional materials are used to optimize the fluid characteristics for the application and also to degrade the water-soluble polymer to make it easier to recover from the well prior to production. The recovered, degraded fluids cannot be used again and must be disposed of in a proper manner. A new hydraulic fracturing fluid system has been developed that provides excellent performance during the fracturing process with post-fracture treatment fluid recovery approaching 100%. This fluid has the added benefit of being reusable after it is recovered following the treatment and prior to production. The benefits of reuse include the cost savings associated with capturing and reusing chemicals, the cost savings because of reduced water volume requirements for subsequent treatments, and the elimination of disposal costs. In addition, the total volume of chemicals required for fracturing operations is significantly less, thus reducing the demand on our environment. Field analyses of the returned fluid determine parameters of maintenance and reconstitution for use in subsequent fracturing. This paper will outline the application of this fluid system, the concept for recycling and reuse, and the procedures necessary to properly use the recovered fluid in subsequent treatments. Introduction Hydraulic fracturing of oil and gas producing reservoirs is an industry accepted technique used to enhance productivity. It plays a major role in the development of many oil and gas fields around the world. The development of fracturing fluid systems has progressed from gelled hydrocarbons to water/oil emulsions to guar gelled water-based fluids to transition metal crosslinked guar-based fluids. Fluid development has continued with the use of surfactant-based fluids and low concentration polymer fluids. Fluid volumes for a fracturing treatment are dictated by the formations of interest in the well. They can range from a few thousand gallons to several hundred thousand gallons. The recovery and reuse of the fluid system can reduce the impact on the environment in several ways. First, the amount of water for subsequent treatments will be reduced by the volume recovered. Second, the required chemicals will be reduced based on the properties of the recovered fluid. Third, the cost of disposal will be saved. The objective of a fracturing treatment is to place a proppant into the created fracture to maintain the open crack and provide a high-permeability pathway for reservoir fluids to the wellbore. The fluid system provides the means to create the fracture and place the proppant in it. The stimulating benefit of a fracturing treatment comes from the proppant holding the fracture open. The fluid system only facilitates the proppant placement and it must be recovered from the well before production can commence. Therefore, it is desirable to capture the fluid so it can be used for another fracturing treatment. Up to this point in time, the polymer-based fracturing fluid had to be degraded in place with strong chemical breakers before it could be efficiently recovered from the well, and it has simply been disposed of in pits or disposal wells. If the fluid systems were simply water, then disposal may not be a great concern. However, most fluid systems are composed of expensive, complex chemical formulations designed to provide specific rheological properties during the pumping of the treatment. Fluids have not been recovered and reused before now because they are purposely degraded to achieve fluid recovery and they therefore no longer have the desired properties for use.
Abstract A system to estimate emissions from large numbers of oil and gas producing properties was developed by the BP's Permian Basin environmental group. The system developed by BP estimates air emissions on a quarterly basis for both internal and external reporting requirements. Additional benefits from the system have been the reduction of fuel gas use and other measures to improve operating efficiencies. This paper describes the key components of the air emission data gathering system, the results of the calculations showing the relative emission levels, and the economic benefits by implementing such a system. The results of the emission reporting system enabled BP to accurately estimate the emissions from each property. Overall emissions for the Permian Basin were quantified. Operations people determined that fuel gas costs could be reduced through the use of lower or no bleed gas operated equipment. The study also helped to prioritize additional engineering work to look at fuel consumption in fired equipment. Internal and external reporting requirements were integrated. Introduction Estimating the air emissions from oil and gas producing equipment has been a goal which industry and regulatory agencies have spent a great deal of study and effort to obtain. The EPA's "AP-42" emission estimating guidelines is the standard for estimating emissions from most fugitive and combustion sources. Additionally, the EPA's "Gas Star" program helped to identify fuel gas emissions sources and rates. In the mid 1990's, the EPA developed guidance documents for estimating emissions from gas plants. The Texas Commission on Environmental Quality (TCEQ; a.k.a. TNRCC) developed guidelines and rules for determining emissions from combustion devices. A joint industry and government initiative produced "Gly-Calc" to determine emissions from glycol dehydration units. The API recently developed guidelines for the calculation of greenhouse gas emissions. Development of these calculation routines, advances in database programs, and internet reporting capabilities has enabled BP to estimate emissions from over 280 properties located in the Permian Basin. BP was the first company to apply techniques jointly developed by government and industry to estimate emissions for a large number of properties. The emission system was developed to meet two goals. The first goal was to gather regulatory required data for reporting emissions to the TCEQ. The second goal of the program was to provide data for an intra-company greenhouse gas reporting and reduction program. Additionally, the program resulted in greater operating efficiencies and a reduction of air emissions. The challenge to BP was to develop an emission reporting system to gather data from over 280 properties containing thousands of different components. Each lease had to be inventoried for the number of wells, gas-treating units, tanks, fired vessels, gas operated valves and pumps, internal combustion engines, fugitive sources and other sources. Fuel gas rates and electrical use had to be determined. A system had to be developed to gather and record thousands of pieces data, perform necessary calculations and then generate information for reports to be used by both regulatory and company entities. The results of the emission reporting system enabled BP to accurately estimate the emissions from each property. Overall emissions for the Permian Basin were quantified. Operations people determined that fuel gas costs could be reduced through the use of lower or no bleed gas operated equipment. The study also helped to prioritize additional engineering work to look at fuel consumption in fired equipment. Internal and external reporting requirements were integrated. BP's Emission Reporting Goals In 1998, BP set a goal of reducing greenhouse gas emission (GHG) to a level of 10% less than the 1990 emission. To achieve this goal, BP developed a comprehensive emission reporting requirement that forced each operating unit to determine and report GHG emissions and criteria pollutants. The Permian Business unit went a step further to integrate the BP corporate required emissions reporting requirements with the state agency requirements.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract It is an obvious statement of fact that every well drilled will reach the end of its productive life. When the well reaches that point, plugging is the appropriate and environmentally sound solution. Unfortunately, there are a large percentage of wells which are idle, not because their resources have been depleted, but because they have become unprofitable due to low product prices or high production and environmental compliance costs. At this time the latter two are more likely. Most idle wells do not pose an environmental threat. Idle wells could potentially provide the states and the nation with much needed domestic production. It is in the best interest of the oil and gas states to insure that no well is prematurely plugged. The states recognize the economic potential of idle wells, but also realize that many of these wells represent potential liability. The responsibility of plugging orphan wells—those where the operator has gone out of business or is insolvent—falls on the states. For some states this is a large burden. Though orphan wells are the greatest burden, the states are usually responsible for monitoring the status of all idle wells. Facing this challenge, the oil and gas states have developed some effective solutions. Introduction The Interstate Oil and Gas Compact Commission (IOGCC) has taken a leadership role on the issue of idle wells in the United States. Beginning in 1992 the IOGCC began surveying the oil and gas states to determine the scope of the idle well problem. The survey was updated in 1996 and again in 2000. Data and conclusions of the three surveys were published by the IOGCC. In 1992 the publication was titled "A Study of Idle Oil and Gas Wells in the United States." The 1996 and 2000 studies are titled "Produce or Plug?: The Dilemma Over the Nation's Idle Oil and Gas Wells." The survey was conducted for the states with the purpose of helping those states solve what in the beginning was a growing problem. In 1999, there were over 340,000 wells idle. This figure represented an increase of more than 58,000 over the number recorded in 1996. To their credit the states recognize the problem and have actively taken steps towards addressing idle wells. This report is based upon the findings of the 2000 study. For the purposes of this report, an idle well is generally defined as a well that is not currently producing or injecting, and has not been plugged. In collecting data for the 2000 idle well study, the IOGCC wanted to get an accurate number for the recognized categories of idle wells. The three categories of idle wells are: wells idle with state approval; wells idle without state approval, where the operator is known; and wells idle without state approval, where the operator is either unknown or insolvent (orphan wells). The Survey and Produce or Plug. To place all the data into perspective a brief description of the survey and the report written from the compiled data is warranted. Information was solicited from 32 states, the Bureau of Land Management (BLM), and Alberta. The survey supplied insights into the many issues, which comprise the idle well problem, and how those problems are being addressed by the states, the BLM and Alberta. Among other information, the survey requested statistics including: the number of wells producing or injecting; wells previously plugged and abandoned; the total number of wells drilled; and the number of idle wells falling into either of the three idle well categories. The 2000 Produce or Plug placed the data into twelve sections: statutory authority and definitions; security or financial assurance; plugging funds and well plugging authorization; approval procedures and technical requirements; data management and well tracking; salvage value of orphan wells; pre-regulatory wells; idle well statistics; energy and environmental concerns; expanded authority or funding, tax incentives, and innovative programs; information on the Bureau of Land Management; and a section on one of the IOGCC international affiliates.
- North America > United States (1.00)
- North America > Canada > Alberta (0.56)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming (0.89)
- North America > United States > Virginia (0.89)
- North America > United States > Texas (0.89)
- (8 more...)
Abstract Industry operators using downhole water separation technology in bottom water drive reservoirs with water coning problem have employed two major approaches. One approach uses downhole hydrocyclone and pumps to separate water from oil in one co-mingled production stream. This approach involves elaborate completion design and high cost equipment. The second approach, termed "gravity segregation" uses dual completion technology with zonal isolation packer to separately produce the water and the oil and so counter the cone development at the wellbore. Both methods, currently, do not completely eliminate the problem of contaminated water production but reduces it to, perhaps, some manageable level. The growing emphasis on environmental-friendly oil production operation and increasing cost of water handling requires the production of oil-free disposable water in a simple completion design. This paper presents case studies of the pre-installation design of gravity segregation method for three fields (West Africa, Gulf Canada and Louisiana) with strong water coning problems. The study confirms that old oil fields that have suffered severe water coning exhibit a transitional saturation profile and dispersed oil-water contact. In addition, the imbibition/drainage process of water cone development and reversal induced by gravity segregation creates relative permeability hysteresis effect. The effects should be included in the pre-installation modeling. The results using numerical simulator, indicate that the combined effects of capillary transition pressures and relative permeability hysteresis are responsible for the production of contaminated water experienced with application of the gravity segregation approach in old oil fields. It also shows how to add an envelope to the well's inflow performance window to accommodate the transition zone. Inside the envelope production of oil-free water from the bottom completion is possible with production of minimal water cut oil at the top. This uncontaminated water could be disposed while operators maximize the use of their pipeline and water separation facilities as well as improve oil recovery. Introduction Oil production from reservoir underlain by water causes the stable oil-water interface to deform into a cone shape. Moreover, continuous production of oil at a rate above the critical oil rate makes the cone oil-water interface (contact) unstable and water breaks through into the wellbore. After breakthrough, the water production increases rapidly. The water production creates several operation problems as follows:Increased water mobility creates by-pass oil in the reservoir High rate water production reduces the utility of pipeline facilities and increase cost of water handling Disposal of oil contaminated produced water creates environmental hazard Corrosion and reduced life of pipeline and facilities. Several mechanisms have been identified as culprits of excessive water production in oil wells from reservoirs underlain by water. Among these causes are channeling behind the casing; perforation into or too close to the water zone; casing leaks around the water zone, depletion of the reservoir during production, creation of fracture in the water zone during stimulation operation; and coning of bottom water into the wellbore. Several methods have been employed by operators to solve the problem of water production in oil wells. One of such solution is to perforate the well high up in the oil zone above the oil-water contact (OWC). This solution delays the time to water breakthrough into the oil well. However, as long as production rate exceeds the critical oil rate, water production is inevitable.
- Water & Waste Management > Water Management > Constituents > Bacteria (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
Abstract ENI-Agip Division is actively working to develop processes increasingly compatible with the environment and health and safety principles, aiming at the best care of HSE aspects for all company's activities. The effort expended to continually improve prevention and protection systems is considerable. At present, Agip Division is actively involved in projects with universities and research institutes as well as associations representing oil companies, as shown by the large number and high level of ongoing innovative and R&D projects. A lot of activity concerns ongoing scientific research projects focused on management of consequences arising from environmental emergencies, definition of monitoring and techniques management systems for clean-up activities, coupling and uncoupling problems related to subsidence modeling and forecasting, etc. Also, the evaluation of accidental consequences after fire, explosion and blowout events is being actively followed. The same approach is adopted in the corrosion management where a combination of the estimated likelihood of failure due to corrosion and the consequence of this failure is assumed to define the level of risk. The paper deals with all the innovative projects presently ongoing and intended to significantly improve Agip's HSE performance in the near future. Introduction ENI Agip Division confirmed its commitment with regard to health, safety and environment, by ensuring that performance was monitored continuously and that HSE issues were kept under constant observation. In every phases of its operating process, ENI Agip Division has identified specific objectives, in terms of health, safety and environment, and has developed technical solutions to limit the impact of its activities. This involves all operating areas: from exploration to development and from production to plant decommissioning. In December 1998, ENI Agip Division has obtained ISO 14001 certification, by the Italian Shipping Registry, of its Environmental Management System for activities in Italy. In 1999, ENI Agip Division drew up and issued a single policy statement on Health, Safety, Environment, Quality and Radiation Protection issues (HSE-QR). This statement spells out the objectives that the Division undertakes to pursue in order to ensure the development and well being of its own human resources and the community at large. The Integrated HSE-QR Management System covers the Division's entire operating process and specifies the most appropriate instruments to protect the environment and the health and safety of employees, contractors and populations exposed to its activities. The new integrated system has made it possible to highlight aspects connected with the prevention, reduction and elimination of quality deficiencies in processes, services and products. On the basis of these agreements, ENI Agip Division is committed to pursuing specific objectives, including the participation in safety and environmental research projects. ENI Agip Division's safety and environmental research effort is mainly directed at the projects that regard traditional research themes such as:"Use of biomarkers in the ecotoxicological monitoring of the Val d'Agri Terminal area", a project concerning activities in the Agri Valley, in Basilicata, coordinated by the University of Siena with the \participation of EniTecnologie.
- North America > United States > Texas (0.28)
- Europe > Italy > Basilicata (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Abstract A mineral extraction Agreement (MEA) is useful in protecting the Land Owners interest while allowing oil and gas development projects to proceed. The combination of the MEA and close cooperation between the Land Owner and Developer can accomplish the objectives of both parties. Introduction Turner Enterprises purchased Vermejo Park Ranch (Ranch) in 1996. The ranch encompasses 588,000 acres in New Mexico and Colorado (Fig. 1). PennzEnergy Company, the previous owner, retained the mineral rights that included the Raton Basin, Coalbed Methane. As part of the property transfer a Mineral Extraction Agreement (MEA) was signed between PennEnergy and the Ranch. The successors to PennzEnergy, El Paso Energy and Devon (Developer) initiated Coalbed Methane development activities on the Ranch in 1999. The MEA established areas of the Ranch that can be developed and also sets out requirements for the development project. The goal of these activities is to minimize impact on the sensitive environments and guest services operations. The paper presents several aspects of the MEA. Ranch Operations Vermejo Park Ranch consists of diverse ecosystems with flora and fauna found almost nowhere else in the Western United States in such a pristine condition. The 588,000 acre Ranch ranges from the high prairie at 6,400 ft to above timberline at nearly 13,000 ft. The land is utilized for a private resort (hunting, fishing, sightseeing), bison ranch, endangered species/wildlife preserve and timber management. The wildlife includes almost 10,000 head of elk, 2,200 head of bison; mule deer, pronghorn antelope, wild turkey, mountain lion, bear and coyote. There are twenty-one stocked lakes and approximately 30 miles of streams with native cutthroat trout. The lakes also support various migratory waterfowl and raptors such as eagles and hawks. Approximately 2500 hunters and fishermen visit the Ranch annually. Coalbed Methane (CBM) Development Exploration activities for oil and gas (coalbed methane) have been conducted on the Ranch since the middle 1900s. Under PennzEnergy's ownership, several wells were drilled in 1989 through 1991 to take advantage of the government's CBM tax credit/incentive program. Some of the wells produced methane from the Raton and Vermejo basin coal seams from 1990 through 1994. Further drilling was not conducted until May 1999, when El Paso Energy and Devon initiated the current development program. In 1999, two central processing facilities (CPFs) including a compressor and produced water-handling equipment were constructed. Drilling activities included 40 new coalbed methane wells, and 2 produced water disposal wells. In 2000, the actives increased to 79 new wells, 11 re-entries and 4 more produced water disposal wells. To handle the increased production, two additional central processing facilities were constructed along with 4 compression stations. Activities in 1999 and 2000 also included the construction or upgrade of over 100 miles of access roads and installation of pipelines, gathering lines and buried electrical cable. The facilities located on the west side of the ranch were connected to the existing operations by a new 23-mile transmission pipeline in 2000. Overhead power (17 miles) was also installed to the Canadian River and Colorado CPF's.
- North America > United States > Colorado (0.77)
- North America > United States > New Mexico (0.56)
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.96)
- North America > United States > New Mexico > Raton Basin (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Colorado Field (0.89)
- North America > United States > Colorado > Canadian River Field (0.89)
Abstract Conoco's St. Charles Field, located in the Aransas National Wildlife Refuge, is a sterling example of profitable oil and gas operations co-existing with wildlife and nature. Since 1939, Conoco's plan for managing the St. Charles Field provides for the minimization of impact to the Refuge's primary whooping crane territories and allows systematic and prudent oil and gas exploration and development of remaining reserves. Through Conoco's culture of environmental stewardship, an ongoing relationship and spirit of cooperation exists with the Refuge and other environmental advocates in the preservation of this environmentally sensitive area. Introduction On the bank of the grassy marsh along the Gulf Intracoastal Waterway, five whooping cranes - a family of three and another pair - stood companionably together, knee-deep in the shallow water. Then some unseen signal from the male chased the trespassing pair off into another nearby area of the marsh. The remaining family of three birds flung back their heads in unison and cried their territorial triumph. The Aransas National Wildlife Refuge is a special place. World renowned as the winter home of the endangered Wood Buffalo Whooping Crane flock, Aransas is also a refuge and breeding ground for other protected species such as the Brown Pelican, Piping Plover, Attwater's Prairie Chicken, Peregrine Falcon, and Bald Eagle. It possesses one of the most abundant and diverse populations of wildlife in the United States with over 400 different species of birds and mammals. The Refuge's landscape is also very diverse, consisting of tidal marshes, wooded dunes, open grasslands, dense oak thicket, freshwater ponds and chaparral communities. The shallow water bays surrounding Aransas are home to a number of marine fish and crustaceans that are of recreational and commercial importance and provide a critical food source to wildlife. he natural resources of the Aransas National Wildlife Refuge are abundant and obvious for all to see. But deep beneath the surface of the Refuge is another resource - petroleum. Hidden under layers and layers of earth, oil and gas were formed more than thirty million years ago. Geologists have determined that through the ages petroleum migrated as the result of natural shifting of the earth and became trapped in formations 7,500 to 12,000 feet deep. And there lies the making of a special partnership… Refuge officials and oil men have been working together in an atmosphere of cooperation and understanding to ensure maximum protection for the wildlife and its habitat and to preserve the natural beauty of the Refuge. For more than 60 years, Conoco has been conducting exploration and production operations on the Refuge; its mineral rights pre-date by three years the establishment of the Aransas National Wildlife Refuge there. Throughout all of the years of exploring and producing oil and gas on the Refuge, Conoco has held a deep concern for the sensitive Refuge environment, especially the endangered whooping crane flock. The whooping crane flock, which winters on the Aransas Refuge, constitutes the last viable population of these endangered birds in the wild. During the years that Conoco has conducted business at the St. Charles Field on the Refuge, the flock has increased from fewer than 20 birds to a recent count well over 180, each making the 2,500-mile migration to and from Canada each year.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.72)
- North America > United States > Wyoming > Charles Field (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > St Charles Field (0.99)
- Asia > Middle East > Israel > Tel Aviv District > Southern Levant Basin > National Field (0.89)
Abstract A goal of CO2 sequestration is to provide economically competitive and environmentally safe options to offset projected growth in baseline emissions of greenhouse gases. The sequestration of CO2 in subsurface formations is a gas storage process. Among the issues that must be considered in a gas storage project are verification of injected gas inventory and monitoring of injected gas migration. This paper uses an integrated flow model to assess the feasibility of monitoring CO2 sequestration in a mature oil field using time-lapse seismic analysis. Introduction One of the most pressing environmental concerns facing society today is global climate change. A purported cause of adverse global climate change is the greenhouse effect. The climatic greenhouse effect occurs when carbon dioxide in the atmosphere absorbs infrared radiation rather than letting it escape into space. The resulting atmospheric heating is attributed to increasing levels of carbon dioxide in the atmosphere. One proposed method for reducing the climatic greenhouse effect is to collect and store carbon dioxide in geologic formations as part of a process known as CO2 sequestration. The International Energy Administration (IEA) has estimated that enhanced oil recovery has the capacity to store 61 gigatonnes of CO2. As a basis for comparison, the Oil & Gas Journal reported in its 14 Feb. 2000 issue (pp. 30–31) that annual greenhouse gas emissions have been estimated by the IEA to be approximately 1.5 gigatonnes of carbon or carbon equivalent. The IEA estimate of enhanced oil recovery storage capacity assumes that 6,000 SCF of CO2 may be stored for each stock tank barrel of oil (0.3 tonnes/STB). A field study conducted in the Avile reservoir of the Puesto Hernandez field in west-central Argentina demonstrated that CO2 may be stored as a result of CO2 injection in an immiscible displacement process. In that case, a reduction of 714,000 metric tons of carbon-equivalent emissions of CO2 and methane was estimated. Significant CO2 sequestration potential also exists in coal bed methane recovery. The sequestration of CO2 in subsurface formations is a gas storage process that must satisfy the three primary objectives in designing and operating natural gas storage reservoirs. Those objectives are verification of injected gas inventory, monitoring of injected gas migration, and determination of gas injectivity. This paper discusses the feasibility of monitoring CO2 sequestration in a mature oil field using time-lapse seismic analysis. The oil field is the East Vacuum Unit in the Vacuum Field, New Mexico (Figure 1). Time-lapse seismic images are obtained by comparing two 3-D seismic surveys conducted at two different points in time in the same region of interest. Differences in seismic response between the two surveys provide information about changes in reservoir properties that effect the transmission of seismic disturbances. These differences are especially useful, when they are significant, because they provide information about the distribution of fluids between wells. Time-lapse seismic monitoring, also called 4-D seismic, is becoming a cost-effective tool for improving reservoir characterization, locating bypassed reserves, and identifying the movement of fluid interfaces. The feasibility of applying 4-D seismic to CO2 sequestration in the subsurface is analyzed here using the integrated flow simulator IFLO. IFLO is a pseudomiscible, multicomponent, multi-dimensional fluid flow simulator. It has been tested under a variety of conditions, including oil and gas reservoir depletion, waterflooding, gas injection into an undersaturated oil reservoir, aquifer influx into a gas reservoir, and carbon dioxide injection. Favorable comparisons with the first SPE comparative solution problem and the fifth SPE comparative solution problem have been obtained. The feature that characterizes IFLO as an integrated flow model is the integration of a petrophysical model with the flow simulator. The petrophysical model is used to conduct forward modeling as part of the flow simulation process.
- North America > United States > New Mexico > Lea County (0.35)
- South America > Argentina > Neuquén Province > Neuquén (0.24)
- South America > Argentina > Neuquen > Neuquen Basin > Puesto Hernandez Field (0.99)
- South America > Argentina > Mendoza > Neuquen Basin > Puesto Hernandez Field (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > San Andreas Formation > Upper San Andreas Formation (0.99)
- (34 more...)
Abstract The offshore oil and gas industry in the UK is currently undergoing a sea change in the way in which environmental aspects of its business are managed. In 1999, the Department of Trade and Industry, the UK's regulator with responsibility for environmental issues offshore, announced its intention to apply elements of the European Directive on Pollution Prevention and Control to the offshore oil and gas industry. In the first instance, the scope of the regulation will cover the generation of power on offshore facilities. From November 2000, all new installations and existing installations undergoing a substantial change will require a permit to operate combustion processes. From 2001 it is proposed to extend this permit system to the control of chemical use and discharge. Further extension of the permit system is anticipated over the following years. By November 2007, all offshore installations will be covered by the regulation and will require a permit to operate. This paper addresses the requirements of the new regulatory regime and the implications for the UK offshore industry. Using the combustion processes regulation as an example, it discusses the information required by the DTI before a permit can be granted and the problems operators may face in meeting requirements of the regulation. Specifically the paper will discuss the problems associated with retrofitting dry low NOx technology, the monitoring of emissions and the benefits of atmospheric dispersion modelling. Wherever possible the paper draws on the experience of operators and uses practical examples to highlight the issues. Introduction The control and management of environmental impacts from offshore oil and gas operations in the United Kingdom Continental Shelf (UKCS) has traditionally been through a mixture of regulatory controls, voluntary agreements and industry led initiatives. In some part, this approach reflects the multinational sources of pollution into the North Sea and the need for pan European agreement on regulation and controls. Recent UK regulations have therefore mainly been a response to co-ordinated action to environmental issues. Increasingly this has meant Europe-wide regulations and agreements to limit, for instance, pollution in the North Sea or to reduce the transboundary movement of pollution. Increasingly this approach appears to be technology led. This paper describes the background to the current controls over the environmental impact from offshore oil and gas operations and describes how this is undergoing major changes. Current controls For many years, regulatory control over the environmental impact from oil and gas operations were derived from international agreements set in place to control the discharge of oil into the sea. In that respect, they were derived from the very public nature of oil spills and the growing international concern over the amount of oil discharged to the world's seas and oceans. Globally this concern was addressed in MARPOL 73/78(1). Within the oil and gas industry in Europe, the work of the Paris Commission led to the adoption of a target standard for free oil in discharged produced water (2). Within the United Kingdom (UK), these controls were introduced via the Prevention of Pollution Act 1971 (POPA). This Act made it an offence to "discharge oil or any mixture containing oil within UK Territorial waters as a result of any operations for the exploration and exploitation of the natural resources of the seabed and sub-soil thereof" without an exemption.
- North America > United States > Texas (0.46)
- Europe > United Kingdom > North Sea (0.45)
- Europe > Norway > North Sea (0.45)
- (2 more...)