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Results
Abstract As drilling and completion technology has advanced dramatically, developing new oil fields faces new opportunities of well structure selection, especially for the fields that are sensitive to issues such as environmental conservation, cost effectiveness, safety control, and well management. Horizontal, multi-branching and multilateral technologies have been used in many field applications all over the world to enhance the reservoir recovery in a cost-effective way. When the well structures become complex, producing from these "fancy wells" could become difficult, and sometimes, detrimental to overall recovery. To study the strategies for optimizing multilateral wells, we have developed a mathematical model to predict well performance for horizontal and multilateral wells using coupled multiphase models of wellbore/reservoir flow. The flow distribution along the laterals is predicted as a function of tubing head pressure (deliverability of the well), and overall well performance as a function of time is predicted by a simple material balance relationship. A common problem for such wells is that commingled production from multilateral branches can often lead to crossflow from one reservoir compartment to another. The likelihood of crossflow depends on initial reservoir conditions, but also very much on the operating conditions of the well. Deleterious interactions between commingled reservoirs accessed by multilateral wells must be reliably preventable for these types of completions to have broad application. Some case studies and hypothetical examples are presented in the paper to show the procedures for optimizing the well structure and well performance. Production strategies that would help to eliminate crossflow are discussed. Introduction To study the effect of crossflow in multilateral wells, we first developed a mathematical model to predict the flow distribution in the well system, which includes the flow profile along each lateral, the flow profile from each lateral, and the total flow rate, as functions of tubinghead pressure. The multilateral well deliverability model couples the calculations of inflow to each lateral, pressure drop behavior in each lateral, and pressure drop in the main wellbore. It finds the equilibrium producing point for commingled production in multilateral wells by iteration. Multilateral Well Deliverability Model The well geometry considered to develop the model is illustrated in Fig.1, using a trilateral well as an example. Each lateral is assumed to be horizontal and connected to the main wellbore with a build section. We also assume in the model that the build sections are non-producing and only provide paths between the horizontal producing sections and the main wellbore. Each lateral horizontal section, each build section, and the main wellbore can have different tubulars from one another. Pressure drops in the build sections and the main wellbore are calculated using a two-phase flow correlation.
Abstract In Hungary, the oil prices in the range of $20 makes EOR projects commercially viable. Because of their structures and fluid properties, the oil reservoirs in Hungary are suitable for gas injection EOR methods. This EOR potential is well supported by favourable infrastructure in the local oil industry/surroundings. The paper presents the EOR application for a large reservoir in the Pannonian basin. The Szeged-Mรณravรกros is undersaturated fractured reservoir with Triassic dolomite, Miocene sandstone and conglomerate at the depth of 2630โ2450 meters below the sea level. The OOIP derived from material balance is 11.56 million cubic meter and oil gravity is 817 kg/m3. The initial pressure was pr=331 bar, initial temperature was tr=140 ยฐC. In the period of the natural depletion between 1975โ1980, the cumulative oil production was 1,27 million cubic meter. In this period, because of the limited water influx, the reservoir pressure dropped below the bubble point and secondary gas cap started to increase. The pressure dropped to pr=244 bar. In 1980, water injection was started to maintain the reservoir pressure. The aim was to increase the reservoir pressure above the bubble point pressure. With this water injection from 1980 to the present time, the oil recovery is 36.4 % with a cumulative oil production of 4.21 million cubic meter. The current reservoir pressure is 250 bar. For studying the further recovery enhancement, laboratory and reservoir simulation studies were carried out to evaluate different gases. Natural gas, nitrogen, and CO2 were selected for the gas injection near the structure top. In Hungary, large CO2 reserves are available 50โ250 km distance from the oil field. The natural gas resources are easily available because of the developed gas distribution network and the production of nitrogen by stripping from the air can be also easily realised. At the optimal pr=250 bar pressure, the displacement process is not miscible in the reservoir, and the recovery increment is not sensitive to the type of injected gas or its quality. The reservoir simulation shows the recovery increment is about 12 %. We have selected nitrogen gas as an injection gas based upon economic and environment evaluations. The paper describes how we arrived at this conclusion in a country where there is a well-developed natural gas market. The paper also includes discussion about the methods and criteria used to select the process. Introduction The amount of the produced oil and condensate coming from the EOR processes is 170,4 thousand tons recently. More than 70 % of the total amount is connected to gas injection technologies mainly to CO2 injection but methane and ethane rich gases are also used as the material of EOR injection mass. CO2 is available from natural resources in the Western part of the country, here is the largest CO2 injection project is taking part. In the central area of the country, only limited natural CO2 resources are available. Here a gas enriching plant is working where the CO2 is forming as a sideproduct. CO2 reservoirs are also in the eastern part of the country but their development has not yet begun because of the lack of utilisation. However the most important oil resources of the country are in the Southern, Southern-East areas relatively far from the above mentioned CO2 areas. Therefore, in this region, studying the possibility of methane and nitrogen injection is necessary because of the limited or cost requiring availability of CO2. A systematic screening was made between 1997โ2000 for the Southern-Hungarian oilfields. The most important conclusion of the study was that the temperature and pressure conditions, the geological features and the PVT characteristics of the reservoir fluids are favourable mainly for the EOR with gas injection.
- North America > United States (0.94)
- Europe > Hungary > Csongrรกd-Csanรกd County > Szeged (0.26)
- Phanerozoic > Mesozoic > Triassic (0.51)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.34)
- Geology > Geological Subdiscipline (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.35)
- Europe > Slovakia > Pannonian Basin (0.99)
- Europe > Serbia > Pannonian Basin (0.99)
- Europe > Romania > Pannonian Basin (0.99)
- (2 more...)
Abstract El Furrial field, is located in the north of Monagas State and was discovered in 1986. It originally contained around 7.5 billions STOIIP. The field is approximately 13 km long and 7 km wide. It produces from two main formations identified as the Naricual and Cretaceous Formations. The gross thickness of the two reservoirs is more than 2100 ft. The oil composition in the Furrial Field changes rapidly with depth from that of a conventional oil (28 ยฐAPI) at the top of the formation to that of an immovable tarmat, at the base of the reservoir. Mainly as a result of the increasing asphaltene content of the crude. PDVSA has devoted intensive engineering studies to define the optimum development strategy and to maximise final recovery. As a result of these studies, production mechanisms were identified early and a reservoir pressure maintenance program was defined to increase the recovery and to sustain production. Simultaneously with the implementation of a waterflood project, engineering studies were continued to determine the feasibility of a gas-injection alternative. These studies showed that complement to the water-injection program and it will increase cumulative oil recovery by around 7.5 % OOIP. Additional mechanistic studies concerning the WAG process for the downdip flanks have been done. The results from these shows increase in the recovery factor by about 7 to 10 % OOIP, due to the miscible gas effect. The studies involve, extensive laboratory work, geostatistical and deterministic reservoir descriptions and cross-sections compositional and black-oil miscible simulation models, to define the best recovery process. At this moment water and gas injection processes are already implemented and are at present injecting about 458 MBWPD and 393 MMSCFD. A mechanistic WAG pilot project is ongoing. Introduction El Furrial field is located in the state of Monagas, Venezuela, approximately 25 Km west of Maturin City, and was discovered by the well FUL-1 in February 1986. This well was completed in the Lower Naricual Formation (Tertiary age). The initial oil in place (STOOIP) is estimated in the Naricual Formation around 7 billion STB. The discovery well FUL-1 found oil of 28ยฐAPI gravity. The initial reservoir pressure was 11,258 psi at 13,800 feet subsea, and at average reservoir temperature of approximately 300ยฐF. This indicates that the reservoir was initially over-pressured. Initially, the production mechanism was natural depletion under rock-fluids expansion. The field produced from two reservoirs identified as the Naricual (Tertiary age) and the Cretaceous (Cretaceous age) Formations. The gross thickness of the two reservoirs is around 2,100 ft. The average porosity is 13% and the average permeability is around 300 md (see Table 1). The pressure maintenance scheme of the Naricual Reservoir in the Furrial field was initially through peripheral water injection. The volume of water injected increased from 400 MBD in 1992 to 550 MBD. At the end of 1998, a miscible crestal gas injection project was initiated, and planned to inject 450 MMCFD. As a result of these pressure maintenance projects, the final oil recovery has been estimated at 3210 MMBls or 47% of the OOIP.
- Phanerozoic > Mesozoic > Cretaceous (0.78)
- Phanerozoic > Cenozoic (0.68)
- Geology > Structural Geology > Fault (0.47)
- Geology > Sedimentary Geology > Depositional Environment (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.58)
- South America > Venezuela > Monagas > Eastern Venezuela Basin > Maturin Basin > Carito Field (0.99)
- South America > Venezuela > Eastern Venezuela Basin > Furrial Field (0.99)
Abstract Hunton Formation is one of the most promising formations producing oil and gas in Oklahoma. The formation has an anomalous producing behavior. At the inception, the wells produce at relatively high water -oil and gas-oil ratios. Eventually, both the WOR and GOR decrease. This results in an increase in oil cut and hence reduction in lifting costs over time. Because of relatively high WOR's, many operators are discouraged from completing the wells, and hence abandoning the effort to produce oil from these formations. This particular behavior has been addressed with different names: de-watering, reverse coning, to name a few. We call this behavior ROC (retrograde oil cut) mechanism. Our goal is to explain various anomalous behaviors in the field production, which can be reproduced by geologically defensible reservoir model. We tested several models by comparing the field data with the simulated behavior. Finally, we converged on to a three-layer model - which is geologically and core data consistent - and can produce various anomalous characteristics. These include decrease in WOR over time, increase in GOR after the well has been shut-in, long transient state behavior of oil production, and the decline in pressure (instead of pressure build-up) after some of the wells have been shut-in for 24 hour periods. We have integrated available core and log data, relative permeability data, geological understanding as well as PVT data to build this model. We tested this model by mimicking production from several wells in West Carney Field in Oklahoma. The implications of understanding the mechanism are enormous. Although we only concentrated on Hunton Formation in one county, Hunton formation extends over 2 million acres in Oklahoma alone. Similar formations also exist in other states, which were deemed unproductive in the past. By correctly understanding the production mechanism, the viability of producing from other similar formations can be better investigated. Introduction The objective of this study was to establish a primary production mechanism by which oil is being produced from the Hunton formation by incorporating engineering and geological information. Hunton formation, though promising in nature, has not been fully developed because of its anomalous behavior. Initially, field development was sporadic and many of the earlier wells were abandoned due to high water production and limited surface facilities for disposing off the excess produced water. With the depletion of the reservoir, oil cut increased, making it feasible to develop the field. Hunton Formation covers approximately 2.7 million acres in Oklahoma (Figure 1a) and in surrounding states of Texas, Arkansas and New Mexico. We concentrated our study to one county, West Carney county, in Oklahoma (Figure 1b). Formation is highly fractured and discontinuous and local variations in geology affect the performance to a great extent. Properties observed at the wellbore are sometimes misleading and the well behaves contrary to the observed properties. Some of the unique characteristics of the field are decrease in WOR over time, increase in GOR after the well has been shut-in, decline in pressure (rather than pressure build-up) after some of the wells have been shut-in, and long transient state behavior of oil production. We have tried to explain these unique characteristics using numerical model and the results from this could be extrapolated to other fields producing in a similar manner.
- North America > United States > Oklahoma > Anadarko Basin > Carney Field (0.99)
- North America > United States > Texas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- North America > United States > Oklahoma > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- North America > United States > Arkansas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
Abstract This paper presents a case study of a successful hydraulic fracturing campaign in the Arman field in western Kazakhstan: the first large scale campaign ever performed by a western service company in Kazakhstan. The Arman field is a mature field, originally delineated in Soviet times, and currently producing from four of the original vertical wells, and from newly drilled deviated (30 to 60 degree) wells. The field is currently under waterflood in three of the producing zones, but formation water is also being produced from wet zones. There is significant gas production, since the wells are all producing below the bubble point, either with ESP's or rod pumps. We believed that hydraulic fracturing had good potential for stimulation in this field since most of the wells were producing with a positive skin. In addition to the positive skin, the reservoir was normally pressured, and also depleted in some zones, limiting the amount of drawdown to about 1000 psi. The wells were also producing water and gas in addition to oil, which further reduced the oil production (by a variety of mechanisms). In this paper, we first describe the hydraulic fracturing operations, and the specific actions taken to deal with difficult features of this reservoir. We then examine the production mechanisms in the reservoir and compare the pre and post-fracture production data. Finally, we evaluate the effectiveness of hydraulic fracture stimulation as a method for improving oil recovery in this type of moderate permeability reservoir under waterflood. Introduction In the spring of 2000, the first fracturing campaign by a western service company took place in Kazakhstan, in the Mangistau Oblast on the shores of the Caspian Sea. In the past, there had been several attempts at fracturing in this area, involving rather primitive methods using diesel and sand, but no significant proppant volumes were placed. In the winter and spring of 2001, a second campaign was completed, following good results from the two wells stimulated in 2000. This paper is a case study considering 12 fracture treatments applied to ten wells in the Arman Field. The producing reservoir has many complications for fracturing (high clay contents, very heterogeneous layering, high water saturation and significant Gas Oil Ratios (GORs)) and is of moderate permeability. In addition, many of the wells are deviated, which can cause problems due to initiation of multiple fractures. Some of the wells had already been producing for some time, and some of them were fractured immediately after being drilled. There is currently a produced water re-injection scheme in operation to enhance recovery and maintain reservoir pressure. The goal of hydraulic fracturing in this medium permeability oil reservoir was to bypass skin damage and increase the near-wellbore permeability to reduce the apparent skin effect of high rate multi-phase flow (oil+water+gas) below the bubble point. The wells are being produced with ESP's or rod pumps with a bottomhole flowing pressure below the bubble point. The fracturing was a great success and the oil production was improved by a factor of 2 to 5. In some cases, the increase in production must have also been caused by an increase in the kh of the well, due to fracture growth into a layer which was not previously in communication with the wellbore.
- North America > United States (1.00)
- Asia > Kazakhstan > Mangystau Region > Mangistau (0.24)
- Geology > Geological Subdiscipline (0.90)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.70)
- Geology > Mineral > Silicate > Phyllosilicate (0.50)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Three-dimensional thermal compositional simulation studies were conducted to evaluate the performance of three horizontal wells under cyclic steam injection and steamflooding in the Bachaquero-01 heavy oil reservoir, Venezuela. In the steamflooding scheme investigated, the horizontal wells were used as injectors with existing (and new) vertical wells as producers. Simulation results indicate:oil recovery of about 15% of original-oil-in-place with cyclic steam injection compared to about 25% under steamflooding with no new producer, and about 50% under steamflooding with additional producers, main benefits of steamflooding are in re-pressurization and improved thermal efficiency, and higher oil recovery with additional wells result from improved areal sweep efficiency. Introduction Located in the eastern coast of Lake Maracaibo, Venezuela (Fig. 1), the Bachaquero-01 heavy oil reservoir lies at about 3000 ft. ss. and contains some 7 billion STB of 11.7 degrees API gravity oil with an in-situ viscosity of 635 cp. Cold production began in 1960, but since 1971 the field was produced under a massive cyclic steam injection system. To-date some 370 cyclic-steam injection wells have produced from the field, yielding an oil recovery of only 5.6% of original-oil-in-place (OOIP). The reservoir pressure has dropped from an initial 1370 psia to its present value of about 700 psia. Oil production peaked at 45 MSTB/D in 1991, and has since declined to its current level of 40 MSTB/D. To arrest production decline, three horizontal cyclic-steam injection wells with horizontal sections of 1280 ft to 1560 ft long were infill-drilled in 1995โ1997 in areas of the reservoir containing vertical cyclic steam injectors. Three separate simulation studies were performed to evaluate the performance of the three horizontal wells under cyclic steam injection and steamflooding. Dimensions of the Cartesian models used were 11ร22ร4, 11ร27ร5, and 12ร20ร6. Reservoir Description Geologically, the Bachaquero-01 sandstone reservoir has been divided into nine intervals, namely (from top to bottom), Arena Principal, HH, GG, FF, EE, DD, CC, BB, and AA (Fig. 2). Arena Principal contains 75% of the reservoir OOIP, while the upper four intervals jointly contain 95% of OOIP. Arena Principal is the thickest and most important reservoir interval. Thickness can exceed 200 ft and values of 150 to 200 ft are very common. Excellent lateral and vertical continuity are evident within this interval. Arena Principal consists mainly of well-developed, highly porous and permeable point bar and braided stream sands with alluvial sediments being present. The HH is the next thickest interval. Net oil sand thickness rarely exceeds 90 ft with an average of about 55 ft. Lateral continuity in the overall extension of the HH interval is good. Vertical continuity is complex and generally poor. Overall depositional setting is that of an alluvial meander belt. Net oil sand thickness in the GG interval is quite variable, ranging from less than 20 ft to more than 100 ft, averaging about 40 ft. Lateral continuity is judged to be only fair while vertical continuity is generally poor. A moderate-to-low-energy alluvial complex dominates the GG interval. Net oil sand thickness of the FF interval averages about 20 ft but is quite variable, ranging from zero to more than 60 ft. Lateral continuity as well as vertical continuity are poor. This interval consists predominantly of low-energy alluvial-plain sediments.
- North America > United States > Texas > Dallas County (0.28)
- South America > Venezuela > Zulia > Maracaibo (0.25)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Tia Juana Field (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Lagunillas Field (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Cabinas Field (0.99)
- (2 more...)
Abstract Carbon dioxide is both the most-recognized greenhouse gas as well as the second most-used injectant in oil fields, after water. This coincidence creates the possibility of injecting previously-vented CO2 to both reduce greenhouse gas emissions and increase oil recovery. Such a project has been evaluated for the Avile reservoir of the Puesto Hernandez field, located in the Neuquen Basin in west-central Argentina. This oil field produces associated gas containing approximately 60 percent CO2, which has previously been vented. The project described below assessed the feasibility of extracting and injecting the CO2 into the field to recover additional oil using an immiscible displacement process. Following an evaluation including core floods, compositional simulation, and facilities evaluation, the process was found both to have technical and economic promise in terms of improved oil recovery, and to result in reduction of both CO2 and methane emissions, the latter being an especially potent greenhouse gas. The success of this type of project would create a unique common ground for those concerned with reducing global warming and those concerned with supplying society's energy needs. Introduction This project evaluated the application of a seldom-used process (immiscible CO2 flooding) in the Avile reservoir of the Puesto Hernandez field, located in the Neuquen Basin in west-central Argentina (see Figure 1), a region with no prior history of CO2 injection. Therefore, all aspects of a gas injection project had to be investigated to arrive at a best estimate of whether the project made technical and economic sense. Described below are the properties of the Avile Reservoir, Puesto Hernandez Field, Argentina; results of the laboratory fluid characterizations and core floods; pilot area compositional simulations and the resulting incremental oil rate projections; the analysis of facility requirements; the impact of this project on greenhouse gas emissions; and the estimated economic viability of the project. Significant tertiary oil recovery potential exists based on laboratory studies of fluids and core materials from the reservoir combined with compositional simulation of the laboratory experiments and a field pilot model. Using a conservative interpretation of the available laboratory core flood data resulted in favorable project economics under base assumptions, with a low likelihood of negative economic returns. The project was estimated to incrementally recover approximately 4.0 percent of the original oil in place, corresponding to 220,000 Sm for the pilot area and 670,000 Sm for the combined pilot and full project expansion. The potential greenhouse gas emission reductions range from approximately 185,000 carbon equivalent metric tons for the pilot to 714,000 carbon equivalent metric tons for the combined pilot and full project expansion. Discussion Reservoir Characteristics. Comprised dominantly of aeolian sand dune deposits, the Avile Reservoir in the Puesto Hernandez Field can be characterized as a monotonous, massive sandstone. Vertical variations in porosity are often subtle and may have limited lateral continuity (see Figure 2). For the purpose of this study, the Avile was sub-divided into a total of eight layers. These eight flow units reflected the maximum number of vertical divisions that have reasonable lateral correlation. Each layer top was picked at the top of a relatively high porosity bed with the shallower reduced porosity thickness assigned to the layer above. The lower portion of the Avile (layers 5โ8 in this study) had more consistent thickness, while the upper Avile (layers 1โ4 in this study) was more variable. Reservoir Characteristics. Comprised dominantly of aeolian sand dune deposits, the Avile Reservoir in the Puesto Hernandez Field can be characterized as a monotonous, massive sandstone. Vertical variations in porosity are often subtle and may have limited lateral continuity (see Figure 2). For the purpose of this study, the Avile was sub-divided into a total of eight layers. These eight flow units reflected the maximum number of vertical divisions that have reasonable lateral correlation. Each layer top was picked at the top of a relatively high porosity bed with the shallower reduced porosity thickness assigned to the layer above. The lower portion of the Avile (layers 5โ8 in this study) had more consistent thickness, while the upper Avile (layers 1โ4 in this study) was more variable.
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquรฉn Province > Neuquรฉn (1.00)
- South America > Argentina > Mendoza Province (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Eolian Environment (0.44)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.44)
Abstract A study using full-field reservoir modeling optimized the design of a miscible CO2 flood project for the Sharon Ridge Canyon Unit. The study began with extensive data gathering in the field and building a full-field 3D geologic model. A full-field simulation model with relatively coarse gridding was subsequently built and used to history match the waterflood. This waterflood model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. Predictions for the CO2 flood used an in-house 4-component simulator (stock tank: oil, solution gas, water, CO2). A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood. P. 265
- North America > United States > Texas > Permian Basin > Salt Creek Field (0.99)
- North America > United States > Texas > Permian Basin > SACROC Unit > Lower Clear Fork Formation (0.99)
- North America > United States > Texas > Permian Basin > SACROC Unit > Cisco Sand Formation (0.99)
- (7 more...)
Abstract Increased interest in gas condensate reservoir which exhibit complexities due to the production of gas, condensates and many times an in-situ oil phase has been observed. As expected, there are definite production problems and exploitation concerns which are at issue with gas condensate reservoirs, or reservoirs which exhibit a combination of gas condensate and oil characteristics. In studying reservoirs of this type, there are three main areas which must be adequately addressed in order to develop an appropriate exploitation strategy. These areas are adequately summarized as:The characterization of the gas condensate fluids The coupling of the inherent phase behaviour and fluid flow in the porous media Implementation into a simulator for forecasting capability This work seeks to provide a summary of important characteristics which must be considered in each of these three areas. The knowledge gained from studying a number of these reservoirs over the years will then be implemented by the authors to provide an example of a possible approach which should be followed for designing production from such a reservoir. Based upon this work, it has been found that the characterization of the gas condensate fluids is strongly influenced by two main factors which include any degree of contamination by a free liquid phase in situ and hold-up of retrograde condensate in the formation resulting in excessive producing GORs. The coupling of the fluid phase behaviour and fluid flow in the rock appears to be governed in the areas of the degree of retrograde condensate accumulation, interfacial tension effects, and mobility effects. Part of this coupling also indicates the difference between critical condensate saturation and residual condensate saturations. Finally, an analysis of techniques to improve retrograde condensate behaviour is described and the necessary components of a reservoir simulator are discussed including results from such a simulation. Characterization of Gas Condensate Systems Condensate reservoirs are inherently more difficult to characterize correctly. The literature shows many differences between gas condensate reservoirs and dry gas reservoirs. Figure 1 provides a fairly typical GOR versus total flow rate response from a gas condensate reservoir. At very low flow rates, one has a high producing GOR and, beyond the certain minimum value in GOR, the trend is again upwards. It is easy to identify why this occurs, but sometimes, when faced with the possibility of having extra sampling runs and spending more time in the field some operators believe that the cost outweighs the benefit. In the same plot the response normally seen for an oil reservoir is also shown. With the oil reservoir, the sampling technique is fairly easy to specify; one must produce the well in the domain low enough so that a constant GOR is produced. Such is not the case with gas condensate reservoirs however. At low flow rates, the liquid hold-up will increase and slugging may result. The increased GOR to the left of the vertical line is due to the low flow rate not providing enough lift to transport the liquids in the wellbore. By contrast, one may be inducing liquid dropout in the reservoir at high flow rates to the right of the vertical line in Figure 1. In this case, as the pressure drops below the dewpoint, the liquid will begin to collect in the near wellbore region. In so doing, produced hydrocarbons will contain less liquid than they should and therefore the GOR will be high. Thus, "At what producing rate should a well be sampled?", the only way that one can adequately respond is if one already knows the character of the fluid and the dynamics of the production well. Since this information is not available, sampling gas condensate reservoirs in an optimal manner can sometimes be non-linear and include some trial and error. P. 545
Abstract The stability of foam in porous media has been investigated by core flooding at pressures from 10 to 300 bar, both in the presence and absence of oil. A C16 alpha olefin sulphonate (AOS) and a fluorinated betaine surfactant was studied. In the absence of oil, both surfactants displayed increasing apparent viscosity with increasing pressure. The functional form of the pressure dependence differed for the two surfactants, however. The apparent viscosity increased by a factor of 30 for C16 AOS, and a factor of 3 for the fluorinated surfactant At 300 bar, the two surfactants performed identically. In the presence of oil (hexane-diluted stock tank oil at low pressure and reservoir oil at high pressure), C16 AOS again displayed increasing foam stability with increasing pressure, while the fluorinated betaine showed the opposite trend. The data from experiments in oil free cores are discussed in terms of the limiting capillary pressure theory, and measured pressure variation of the surfactant solution surface tension. The effects of oil on foam stability was assessed by measurement of spreading and entering coefficients at different pressures. For C16 AOS, no change in these coefficients was observed between 20 and 300 bar. For the fluorinated surfactant both coefficients changed significantly, to values indicating detrimental oil-foam interaction at high pressure. Thus, the change in oil-foam interaction seem to explain that the fluorinated surfactant did not show increasing foam stability with pressure in the presence of oil. The observations show that both the foam stability in absence of oil and the oil-foam interactions varies differently with pressure for different surfactants This implies that flooding experiments at reservoir pressure are required for a proper screening of foamers. Introduction Foam confined inside a porous medium has several properties that are desirable in order to control the flow of gas. It has been used, or considered used for, increasing the sweep efficiency of injected gas by reducing gas mobility and thereby avoid viscous fingering, gravity override and excessive flow through high-permeable regions. Foam has also been used for treatment of production wells suffering from unacceptably high gas/oil ratios. A foam treatment will ideally require specific foam properties that depend on the treatment process that is to be implemented, e.g. a foam with moderate mobility that is to be transported deep into the reservoir, or a strongly blocking foam that shall only penetrate a short distance into the reservoir. The foam properties offered by a given surfactant will depend, besides of the type of surfactant and its concentration, on the conditions inside the porous medium in question, such as type of reservoir oil, gas, brine, rock, wettability, temperature, pressure and other factors. At present, there is no general knowledge available that can be used as a guide in choosing the optimal surfactant for a given application. For a specific gas problem to be solved, a surfactant must be chosen between a vast number of excising surfactants. Already at an early stage many surfactants can be eliminated as possible candidates, due to factors such as low and high temperature tolerance, cost, and industrial availability. Nevertheless, at a stage in the selection process, there will usually exist several surfactant candidates that are to be subjected to further screening in the form of core flooding experiments. P. 543
- North America > United States > Oklahoma (0.28)
- Europe > Norway > North Sea (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.98)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.98)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.98)
- (15 more...)