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Collaborating Authors
Canada
Abstract Ansai field is a typical field with low permeability, low pressure, low production and the water flooding is inefficient. In order to explore an effective developing method for increasing the production and ultimate recovery, we carried out the feasibility studies of natural gas flooding. This paper analyses the feasibility of natural gas flooding from the geological condition of Ansai field at first, then introduces the high pressure slim tube tests for determining MMP of injection gas and reservoir oil and prediction of MMP with published correlation. The high precision correlation has been selected for predicting the composition of injection gas in miscible displacement. The performance of natural gas flooding have been simulated using MVIP simulator. The results shows that Ansai field shares the geologic conditions for natural gas flooding. The MMP of lean gas and Ansai reservoir oil is above 32MPa, and the average reservoir pressure is only 8.81 MPa in Ansai field, so the lean gas flooding is immiscible displacement at Ansai reservoir condition. If accomplishing a miscible displacement at the same condition, the composition of injected gas must be changed by increasing rich gas content, the content is 80%C2H6. The results of numerical computations shows that the recovery ratio of natural gas flooding (26.3%OOIP) is more than of water flooding (20.6%OOIP).Obviously, the natural gas flooding is a hopeful EOR method in Ansai field. These studies provides scientific evidence for the policy of natural gas flooding in Ansai field. P. 371
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Brassey Field (0.99)
- Asia > China > Shaanxi > Ansai Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (2 more...)
Abstract In recent years there has been an increasing interest in water-alternating-gas (WAG) processes, both miscible and immiscible. WAG injection is an oil recovery method initially aimed to improve sweep efficiency during gas injection. In some recent applications produced hydrocarbon gas has been re-injected in water injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG has been attributed to contact of unswept zones, especially recovery of attic or cellar oil by exploiting the segregation of gas to the top or accumulating of water towards the bottom. Since the residual oil after gas flooding is normally lower than the residual oil after water flooding, and three-phase zones may obtain lower remaining oil saturation, water- alternating-gas has potential for increased microscopic displacement efficiency. WAG injection, thus, can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and also leading to improved microscopical displacement. This study is a review of the WAG field experience as it is found in the literature today from the first reported WAG in 1957 in Canada and up to new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG with hydrocarbon or non-hydrocarbon gases. Wellspacing is very different from onshore projects (where fine patterns often are applied) to offshore projects (well spacing in the order of 1000 meters). For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5-10 per cent of the OIIP. Very few field trials have been reported as unsuccessful, but operational problems are often commented. Though, the injectivity and production problems are generally not detrimental for the WAG process, special attention has been given to breakthrough of injected phases (water or gas). Improved oil recovery by WAG is discussed as influenced by rock type, injection strategy, miscible/immiscible gas, and well spacing. P. 357
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > North Dakota (0.93)
- (4 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
Abstract Designing gas injection projects in naturally fractured reservoirs requires special considerations which, in turn, relies on knowledge of the fracture network. Characterization of the fracture network involves delineation of important physical characteristics, such as fracture spacing, fracture orientation, fracture conductivity (of both natural and hydraulically induced fractures). Of equal significance is understanding the transfer mechanisms between oil and gas in the rock matrix and injected water and gas present in the fracture network. Integration of fracture characterization with results obtained during experimental investigation of transfer mechanisms is a key step for history matching and predicting reservoir response to water or gas injection. This paper describes the steps taken in two important areas of 1) fracture characterization and 2) fluid exchange from fracture to matrix as a precursor for design of a 10 acre CO2 pilot in the naturally fractured Spraberry Trend Area. Fracture and matrix characterization are based on oriented vertical and horizontal core taken from Upper Spraberry reservoirs. Fluid exchange mechanisms are investigated in reservoir plugs and whole core at reservoir temperatures and pressures. Results of imbibition/wettability and CO2 gravity drainage experiments are presented. History matching Spraberry waterflood performance and predicting performance. under CO2 injection is presented based on integration of reservoir characterization and laboratory experimentation. P. 325
- North America > United States > Texas > Midland County (1.00)
- North America > United States > Texas > Martin County (1.00)
- North America > United States > Texas > Howard County (1.00)
- North America > United States > Texas > Dawson County (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)
- 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)
- (24 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract Mexico's new development and modernization strategy for the natural gas industry and market is based on two pillars: public and private investment, PEMEX, a public organism, is responsible for upstream development, whereas the private sector is in charge of downstream development. In view of macroeconomic constraints, PEMEX is currently facing difficulties in financing its activities. The government is thus discussing whether to authorize a partial opening in exploration and production activities through a special type of service contract. As for the private sector's participation in transport, storage and distribution, there are still institutional, regulatory, entrepreneurial and legal questions pending that may delay or inhibit investments. PEMEX's performance is crucial for private capitals to set up and survive in the spaces that have been opened to them. Mexico's full integration to the North American natural gas market is advancing slowly since there is still a need for substantial changes in assets ownership. In any case, it is very likely Mexico will participate as a net exporter in the medium- and long-terms. Introduction There is great speculation about Mexico's future participation in the North American natural gas market. Numerous studies take it for granted that Mexico will continue being a net importer at least throughout the next decade. This conclusion is based on the NAFTA relative failure to open up the Mexican oil and gas industry and on the Salinas Administration's reluctance to introduce structural changes in this field. A series of decisions taken by Ernesto Zedillo in 1995, however, seems to call into questions the general agreement the entrepreneurs, financiers and scholars had reached. On the hand, Petroleos Mexicanos (PEMEX) is allotting more resources to gas production and its priority goal is to create a real market and to open up to private investment in all segments of the natural gas chain, excepting upstream segments which are to remain restricted. The new course of the Mexican gas policy brings up old questions as well as giving rise to others: When will the private sector be allowed to directly participate in exploration and production? Will PEMEX have enough financial resources to develop non associated gas reserves? Will the changes succeed in mobilizing private capitals? What repercussions will Mexico's integration to the North America natural gas market have? Lastly, will Mexico become a large-scale importer or, on the contrary, a large-scale exporter? The Mexican gas policy: a three-act play Seven different factors have determined the changes in the Mexican natural gas policy: at an economic level, the relative profitability of natural gas exploitation vis-a-vis that of crude oil, the state of the economy, the aspects of energetic security and the situation of the North American gas market; at a financial level, capital availability to favour gas processing and mass consumption; at a political level, the state of bilateral relations with the United States; and lastly, the importance give to environmental issues. The importance of each factor has varied throughout time. Tree clearly defined stages can, nevertheless, be appreciated. Stage one: natural gas subordination to the oil policy. From oil nationalization in 1938 to 1987, natural gas exploration and development were determined by the crude oil production needs. Such a preference can be explained, on the one hand, by the fact that crude oil projects have proven more profitable due to the price difference existing between both hydrocarbons and, on the other, by the high cost of creating an infrastructure to transport gas to the different consumer sectors. It is not surprising that consumption has, in general, remained restricted to the areas surrounding the production centers and that it should have grown at a limited rate. The national energy self-reliance policies did not allow consumers to resort to foreign markets. Although during the oil boom (1977-1981) the financial limitations were relaxed considerably, the Lopez Portillo Administration preferred to invest in gas exploration projects instead of taking advantage of the opportunity to increase internal consumption. The gas hydrocarbon surpluses related to the explosive growth crude oil production were seem as an additional source of foreign exchange to finance the outrageous government plants of those days. Mexico should have taken advantage of the opportunity represented by the U.S. energy crisis. The negotiations between both governments were marked by conflict, specially around the price issue. P. 267
- Government > Regional Government > North America Government > Mexico Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
- (2 more...)
Abstract During the past three years, Marathon has utilized a variety of "high energy" stimulation techniques on approximately 150 wells to enhance near-wellbore conductivity. The majority of these high energy stimulation treatments have been conducted in naturally fractured limestone and sandstone intervals. A number of specialized tools to improve field operations have also been developed. The high energy stimulations utilize pressurized gas (usually nitrogen), to inject various fluid systems into the formation. These fluid systems have included clear liquids (such as acids and alcohols) and fluids containing proppants to scour and prop the created fractures. High viscosity fluids containing proppants were overbalance surged into the formation in some applications. A tubing conveyed perforating (TCP)/proppant carrier system was developed, allowing release of proppant into the fluid stream at the instant of detonation. Typical overbalance surge pressure gradients are 1.5 - 2.0 psi/foot; however, some wells have been stimulated at pressure gradients in excess of six psi/foot. The paper will also discuss the results of directional radioactive tracer logs that were run to determine the number of fracture planes created with these high energy stimulations. A listing of some recommended types of data acquisition and key operational recommendations are included in this paper. Introduction Marathon began utilizing the extreme overbalance stimulation methods in early 1993, approximately six months before articles were published in the literature. These articles began to indicate better inflow performance could be obtained under certain reservoir conditions by the use of extreme overbalance perforating, when compared with underbalanced perforating methods. In many instances, there is insufficient reservoir pressure remaining to effectively underbalance perforate the well as suggested by King and others in the literature. The general method of extreme overbalance perforating involves applying high pressure to the wellbore (at least 160% of fracture gradient) at the instant of perforating gun detonation. Data suggested that all of the perforations were likely to be fractured. Pressurized nitrogen was utilized as stored energy in the tubing to increase the length of time that the fracturing event continued. In addition to improved productivity, this technique was allowing faster completion times and early production, which was economically advantageous. The remainder of this article describes the experiences and perceived improvements in tools and techniques within Marathon during the past few years. Methods utilized include extreme overbalance TCP and surges with liquid systems (acids, water, oil, and alcohols), surges with proppant laden fluid systems, and TCP proppant carrier systems. Surge tools include differential shear surge tools, absolute surge valves and pump-through absolute shear valves. Initial Jobs The first successful job within the company was performed by spotting 500 gallons of 15% hydrochloric acid across and above the carbonate interval to be perforated. The 8-5/8 inch outside diameter casing was pressurized with 8.45 lb/gal brine and 30 feet of wireline perforating guns were detonated at an equivalent gradient of 0.9 psi/ft. (180% of fracture gradient). In retrospect, this first job is now viewed as an undesirable approach due to the very low amount of stored energy obtained by compressing only liquids. Field results from the job were promising, however. The treatment resulted in production comparable to offset wells where large volume acid jobs with ball sealers for diversion were utilized (or each individual foot of the interval was stimulated using dual packer isolation tools). Use of the extreme overbalance technique rapidly progressed within this and other regions of the company due to continued positive results. Stimulation methods were revised to include nitrogen as the energizing gas and multiple interval stimulations became common. To date, approximately 150 jobs have been performed. In some instances, the technique is the only stimulation performed on the well. P. 181
- North America > United States > Texas (0.69)
- North America > United States > Wyoming (0.46)
- North America > United States > Mississippi > Marion County (0.24)
- North America > United States > Wyoming > Bighorn Basin > Oregon Basin Field > Tensleep Formation (0.99)
- North America > United States > Wyoming > Big Horn Basin > Oregon Basin Field > Tensleep Formation (0.99)
- North America > United States > Montana > Bighorn Basin (0.99)
- (5 more...)
Abstract The application of Progressing Cavity Pumps ("PCP's") for artificial lift is still new compared to other technologies. The technology is advancing rapidly and that, combined with new techniques which are learned empirically, continually expands the range of applications. Continuous review is necessary to stay abreast of the technology. This paper discusses the state of the art and the directions in which it is going. Increasing the range of application of PCP's is mainly dependant upon the advancement of elastomer technology. A review of the elastomers now being used or tested, their application and how they are made, is presented. Rotor life is often the determining factor in PCP life. PCP suppliers are doing novel work in plating and hardening of rotors. Some of this work is described. As the displacements of PCP's increased and they were used at greater depths, the increasing torsion on the drive strings created a serious safety hazard and the drivehead designs became increasingly inadequate for the larger loads. The status of the work to create a set of standards which can be incorporated into safety legislation, and upon which petroleum engineers can rely to select driveheads for safety and reliability, is described. This includes the design criteria which must be considered in the selection of a drivehead. The status of the work on ISO norms is also reviewed. Two novel applications for wellbore PCP's are revealed. The conclusions and recommendations summarize the applications and limitations of PCP's for artificial lift. Introduction The PCP is a type of spiral gear pump. The principle of the PCP was disclosed by Mr. Rene Moineau. Oil well PCP's are very simple pumps consisting of only 2 parts; the stator which is usually attached to the end of the tubing, and the rotor which is usually attached to the end of a sucker rod string. In this case, the pump is powered by rotation of the sucker rod string. The principal and the geometry of the PCP which make it the best sludge pump and particularly suitable for the pumping of deep wells, have been described in previous papers. PCP's first found wide application in Canada, for pumping sand-laden heavy oil. The capital cost and operating cost advantages led to the application of PCP's for artificial lift of medium crude, usually with high volumes of water. This required the development of high volume pumps with elastomers which resist aromatic solvents and H2S. PCP's with high head rating were first developed for pumping high viscosity crude oils, but can also be used to lift low viscosity crude from deeper wells. This has lead to the requirement for pumps which resist high temperatures and the high aromatic solvent contents of some light oils. Steam flood applications also introduce the requirement for high temperature resistance. PCP's have also been used extensively in the USA for the dewatering of methane coal-bed wells, although they have been phased out in most fields in favour of small pump jacks as the water production declined. Elastomers The heart of the PCP and, potentially, its "Achilles tendon", is the elastomer in which the stator profile is moulded. Physical Properties. An elastomer is defined as a material which can be stretched repeatedly to at least twice its original length and return rapidly to virtually its original dimensions. The requirements for a suitable elastomer for a PCP are demanding because it must maintain a seal between the cavities and resist fatigue failure for approximately 500,000,000 cycles under rapidly cycling dynamic conditions. (The pumps are operated at speeds up to, and sometimes exceeding 500 rpm). It must also resist chemical attack by the fluids being pumped and abrasion from particulate materials suspended in the fluid. The elastomer must be strong enough to resist shear and tearing forces resulting from the differential head of fluid between suction and discharge. The standard mechanical properties of elastomers that a PCP manufacturer must control are:โModulus of elasticity (mPa): the force required per unit area to stretch a standard test piece of the material a unit of length, โHardness (Shore "A"): the force required to deform the surface of the material, โShear strength (mPa): the force per unit area required to shear the material, โInitial tear strength (mPa): the force required to initiate a tear, โUltimate tear strength (mPa): the force required to propagate a tear, and โAbrasion resistance: the ability of the elastomer to resist loss of material due to abrasion (measured on a knurled wheel under standard ASTM conditions) In addition to the above standard tests, the manufacturers of PCP's must control the recoil rate, the fatigue resistance and the permeability of the elastomer.
- Geology > Rock Type > Sedimentary Rock (0.34)
- Geology > Petroleum Play Type > Unconventional Play (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Michigan > Michigan Basin > Antrim Shale Formation (0.99)
- North America > Canada > Ontario > Michigan Basin (0.91)
Deepwater Production Systems for the Bay of Campeche
Heideman, J.C. (Exxon Production Research Co.) | Finn, L.D. (Exxon Production Research Co.) | Hansen, R.L. (Exxon Production Research Co.) | Santala, M.J. (Exxon Production Research Co.) | Vyas, Y.K. (Exxon Production Research Co.) | Wong, P.C. (Exxon Production Research Co.) | Pontigo, F.A. (Exxon Exploration Co.)
Abstract Deepwater production systems are considered for the 300-500 m water depth range in the Bay of Campeche. In comparison with the northern Gulf of Mexico, the physical environment is found to have similar seafloor soils; similar winter storms; no Loop Current; less severe hurricanes; and weak earthquake-induced groundmotions. Oil reservoirs are expected to be larger than those in the northern Gulf, and well flow rates greater. Under these conditions, and based on industry experience in various offshore oil provinces, steel piled jackets, compliant piled towers, tension leg platforms, and floating production systems, alone or in connection with subsea production systems, are all judged to be technically viable candidates for full-field development with permanent structures. Introduction So far, production of the prolific reservoirs in the Bay of Campeche has been limited to water depths less than 200 m (Figure 1). These reservoirs are characterized by heavily faulted limestones having high vertical and horizontal permeabilities (Franco, 1978). Saturated oil column thickness is typically several hundred meters and areal extent of the larger reservoirs ranges from 10 - 90 square km (Santiago and Baro, 1990; Downer, 1978). Well production rates are high. Wells in the Akal and Nohoch fields produced an average of 35,000 bopd in their early years (Rintoul, 1981). Rates of 16,000 bopd have been common throughout the Campeche fields (Baker, 1985). While most of the oil is the heavy Maya crude, with an API gravity of around 20 to 30, some of the fields have the lighter lstmo crude, with an API gravity of around 30 to 40 (Madeley, 1981; Santiago and Baro, 1990). The gas/oil ratio averages about 650 scf/bbl (Santiago and Baro, 1990). The gas contains H2S (Anonymous, 1979). Production platforms are steel piled jackets. Gas, oil, and water are separated on the platforms, and then oil and gas are piped to shore for further processing and disposition. It is anticipated that similar reservoirs will be discovered in the deeper continental slope water to the west of the known reservoirs, as shown in Figure 1. These reservoirs are expected to have heavier crude (23-30 degrees API) with lower gas/oil ratios (around 200 scf/bbl). The purpose of this paper is to discuss production systems that could be used to develop reservoirs in water depths of 300-1000 m, with emphasis on the 300-500 m depth range, which would likely be explored and developed first. In the following sections, the physical environmental conditions affecting platform and pipeline design are discussed first. Then, the pros, cons, and selection drivers of candidate deepwater production systems are discussed, and recent experience is described. Finally, some economic considerations are discussed. P. 161^
- North America > Mexico > Campeche (1.00)
- North America > Mexico > Gulf of Mexico > Bay of Campeche (0.86)
- North America > United States > Texas (0.68)
- South America > Chile > Santiago Metropolitan > Santiago (0.65)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.70)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- South America > Brazil > Campos Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Garden Banks > Block 388 > Garden Banks 388 Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- (15 more...)
Abstract The following is an update to an earlier paper compiled and presented in April 1991 at the ESP roundtable held in Houston, Texas. This paper contains referenced categories of problems that have been encountered in field operations and the solutions that have been found to the problems. The discussion for each problem/solution set is brief, but serves as an index to the particular reference, where more detail can be found. The discussion is restricted to field cases. Many excellent studies such as design techniques and recommended procedures are not covered since they are not in the context of a field study containing problems and solutions. Also, some field operational papers were not included if they presented identical information. This study was originally intended to be review of the field cases and a summary of various failures and their causes as a function of the conditions present. However, when beginning to review the papers in the literature, it became obvious that it is rare for a given paper to list detailed field conditions. In fact out of the fifty or so references examined here, only a few contained sufficient field condition data which would have allowed problems and solutions to be correlated to conditions. In addition to categorized and referenced problems and solutions, new innovations, products and operating techniques are presented. Summary of Problems and Their Solutions Beginning at the surface, equipment and associated problems and solutions to these problems mentioned in the 105 paper bibliographies of the field cases will be presented. Some of the solutions will appear to be very obvious or simple, but the appearance of the problem and solution will allow the user to reference the paper where it originated and to read in further depth on the subject. A tabular format is used to present the problems and solutions provided in the case studies. It will be subdivided by whether it is a reservoir, completion, or equipment problem/solution category. In each category, the survey that will be given includes: Ref: The reference number of the paper from the bibliography. #ESP. The number of ESPs reported, in the paper, installed. Yr: The year the paper was published. Location: The geographical location of the field. Problem: A short description of the problem. P. 249^
- North America > Canada (1.00)
- North America > United States > Texas > Harris County > Houston (0.55)
- North America > United States > California > Los Angeles County (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > United States > Texas > Maverick Basin > Pearsall Field > Austin Chalk Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Talco Field (0.99)
- North America > United States > Colorado > Vega Field (0.99)
- (27 more...)