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Phanerozoic
Well Planning Under Uncertainty: Application of a Systematic Procedure for Risk Assessment and Uncertainty Analysis for New Well Targets on the Brage Field
Hersvik, Karl J. (Norsk Hydro A/S) | Aanonsen, Sigurd I. (Norsk Hydro A/S) | Petersen, Lasse S. (Norsk Hydro A/S) | Fjellbirkeland, Hege (Norsk Hydro A/S) | Robson, Adrian (Norsk Hydro A/S) | Sperre, Thomas (Norsk Hydro A/S)
Abstract The Norwegian North Sea Brage field came on production in Sept. 1993. The field is currently producing approx. 8000Sm3/d and is on steep decline from its plateau rate of 19400Sm3/d. In March 1999 it was decided to stop the drilling for approximately one year. During this year new reservoir models were built and history matched. Although this work proved to be both complicated and tedious it was fairly successful. However there was still a high degree of uncertainty in the understanding of the flow pattern and the pressure behaviour of the field. It was therefore decided to perform a comprehensive uncertainty analysis to get better estimates of the expected production and risk related to a resumed drilling. The analysis was performed both on a well to well basis and combined into a drilling campaign. The paper will describe analysis in detail illustrated with field examples. A reservoir simulator is utilized to estimate the unconstrained well potential for each well. Then total field water handling constraints is imposed using a tool that optimizes the production given the individual well profiles and the platform constraints. This gives a basis for determining the base case Present Value, PV, for each well's contribution to the field production. For each well target, the most important uncertainties with corresponding probability distributions are identified, and their effect on the PV determined by simulations. In cases where the simulation model is judged not to represent the reservoir behaviour correctly, analytical methods are used. Finally, these results are used together with the drilling cost into a Monte Carlo simulation loop to determine probability distributions for the NPV of each well and for the total drilling program. It is shown that even though most of the individual well targets has a high risk of a negative NPV, the economy of the total drilling program is robust and has a significant upside economical potential. The procedure, which is based on commercially available software only, has proven to be very flexible. It is easy to incorporate new uncertainties related to a well target, or to include or exclude a well target from the drilling schedule. Finally, the resulting NPV probability distributions provide an easy way of ranking well targets based on expected NPV and risk. Introduction The Brage Field is located in the Norwegian North Sea approximately 120 km west of Bergen in Block 31/4, close to and East of the Oseberg Field. The field consists of three separate reservoir unitsFluvial deposits of the lower Jurassic Statfjord formation Shelf to shore-face deposits of the middle to upper Jurassic Fensfjord Formation Shelf to shore-face deposits of the upper Jurassic Sognefjord formation Except for a single well producing from the Sognefjord formation, all the current Brage wells are located in the Fensfjord and Statfjord. Only the Statfjord and Fensfjord formations will be described as all the wells currently planned will produce from these formations.
- Europe > Norway > North Sea > Northern North Sea > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Oseberg Formation (0.99)
- (34 more...)
Abstract Reservoir compaction is a positive contributor to reservoir energy and hence hydrocarbon recovery. Reservoir compaction above a certain magnitude, however, will result in casing deformation and, in some cases, well collapse in standard oil well constructions. Large amounts of reservoir compaction will also induce seafloor subsidence and potential risk to platform constructions and pipelines. The Valhall field is a chalk reservoir in the southern most part of the Norwegian sector of the North Sea. The highly porous chalk (in excess of 50% in many cases) is weak and loses a significant part of its original porosity when the effective stress increases during hydrocarbon production (pore pressure depletion). This pore collapse causes reservoir compaction, and currently the associated seafloor subsidence has reached 4 meters at the platform complex. Since Valhall production was initiated in 1982, the recoverable reserves have been upgraded from approximately 250 MMSTBO to 700 MMSTBO. At the same time 28 out of 102 production wells have been sidetracked due to severe tubular deformations. Most of these deformations (60%) have occurred in the overburden. The first casing deformations in the reservoir were experienced almost instantaneously as a result of chalk production and near wellbore compaction. The first casing deformation experienced in the overburden which resulted in the need for a sidetrack was in 1986, when the seafloor had subsided less than a meter. The work performed through the years to analyze the available data indicates mostly shear loading of the casing in the overburden. Some of the well failures in the reservoir are due to shear loading as well; others are due to cross-sectional collapse, while still others are buckling failures. With the amount of reservoir compaction experienced so far, and the amount expected with continued hydrocarbon production from Valhall, one expects casing deformations to be part of the operational cost. Experience from other fields indicates that one can not stop the compaction and associated kinematics, so the best strategy will be to extend well life as well as possible with minimal cost additions to standard oil field well constructions. Even if the additions are low cost, there is a potential for optimization and risk reduction if better prediction capability could be developed for the casing deformations. Passive seismic monitoring is a relatively new technology in the oil and gas industry. Seismic geophones are installed in wells in order to record small micro-seismic events induced by hydrocarbon production of fluid or gas. The technology has not been explored in great detail in the industry so far. It has the potential to provide useful engineering information for reservoir management in the areas of earth stress determination, waterflood monitoring and hydraulic fracturing monitoring (both stimulation and waste injection). This paper discusses a field test of passive seismic monitoring performed at Valhall and how the data collected can be used in well and casing design. An array of six geophones installed in a well above the reservoir recorded 572 micro-seismic events over a period of 57 days. The events ranged from 0 to 10 per day in the vicinity of the observation well. The data recorded can be processed to yield useful information for a risk based well and casing design at Valhall in order to optimize well life.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.47)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Optimising Performance of Mature Reservoir: An Innovative Use of Coiled Tubing Drilling Technology to Tap Unswept Reserves, Alwyn North UKCS
Lheure, S. (TotalFinaElf Exploration UK plc) | Müller, S. (TotalFinaElf Exploration UK plc) | Kimber, R. (TotalFinaElf Exploration UK plc) | Holehouse, S.G. (TotalFinaElf Exploration UK plc)
Abstract This paper describes the rationale, the planning and the preliminary results of the first Coiled Tubing Drilling (CTD) experience for TotalFina. The objective was to enhance production from a high water-cut oil well producing under unstable conditions and located in an area of possible upsides. This well was drilled in 1990 on the edge of a fault-scarp degradation complex in the Brent East panel of the Alwyn Field. The geological uncertainties in this complex area needed to be reduced and it was necessary to reassess seismic, core and reservoir data to progress the current knowledge base. Analytical calculations supported 3D reservoir modelling techniques to constrain some of the uncertainties. Drilled in 1999, well 3/9a-N30Y was the first coiled tubing sidetrack from a producing well on Alwyn. The motherbore, 3/9a-N30, was still producing around 380 stb/d, although production had recently become intermittent. The well path presented a challenging trajectory due to the location of the unswept area in relation to the direction of the motherbore. After drilling 240m a series of operational issues arose, necessitating the drilling of the world's deepest open hole sidetrack with coiled tubing, but ultimately the BHA was left in hole. The coiled tubing was then utilised as an uncemented liner, perforations using slim guns were added along the liner, and the well was brought onto production. The CTD drain alone produced at an initial rate of 2900 stb/d, which stabilised out at 1200 stb/d after an initial rise in water cut. The successful outcome of 3/9a-N30, which was drilled in a complex offshore environment, confirmed the viability of CTD as a technique for accessing smaller pockets of remaining oil, whilst some of the operational difficulties encountered highlighted the need to simplify future trajectories to maximize the chance of success. With the possibility of drilling future CTD wells, further increases in productivity and reserves will be achieved at a significantly lower cost compared to conventional drilling. Introduction and Background Field Discovery, Appraisal and Development. The Alwyn North field (blocks 3/4a and 3/9a) is owned at 100% and operated by TotalFinaElf Exploration UK (Fig.1). It is situated in the South-eastern part of the East Shetland Basin in the UK North Sea, approximately 140km east of the Shetland Isles. The field was discovered in 1975, with gas and condensate in the Upper Triassic and Lower Jurassic Statfjord Formations, and undersaturated oil in the Middle Jurassic Brent Group. These reservoirs are separated by the Lower Jurassic Dunlin Group shales. The Brent reservoir pressure was initially 453bar at 3231mTVDMSL, and the Statfjord 496bar at 3580mTVDMSL. The field is divided into distinct compartments by a major NNW-SSE trending fault and by secondary ENE-WSW transverse faults. The major "spinal" fault separates the field into East and Western panels, while the transverse faults subdivide the western panels into North, North-West, Central-West, and South-West panels. Oil production commenced in November 1987 from the Brent reservoirs, followed by gas and condensate from the Statfjord reservoir two months later. Field Discovery, Appraisal and Development. The Alwyn North field (blocks 3/4a and 3/9a) is owned at 100% and operated by TotalFinaElf Exploration UK (Fig.1). It is situated in the South-eastern part of the East Shetland Basin in the UK North Sea, approximately 140km east of the Shetland Isles. The field was discovered in 1975, with gas and condensate in the Upper Triassic and Lower Jurassic Statfjord Formations, and undersaturated oil in the Middle Jurassic Brent Group. These reservoirs are separated by the Lower Jurassic Dunlin Group shales. The Brent reservoir pressure was initially 453bar at 3231mTVDMSL, and the Statfjord 496bar at 3580mTVDMSL. The field is divided into distinct compartments by a major NNW-SSE trending fault and by secondary ENE-WSW transverse faults. The major "spinal" fault separates the field into East and Western panels, while the transverse faults subdivide the western panels into North, North-West, Central-West, and South-West panels. Oil production commenced in November 1987 from the Brent reservoirs, followed by gas and condensate from the Statfjord reservoir two months later.
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/8 > Ninian Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/3 > Ninian Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/29 > Brent Field (0.99)
- (12 more...)
Abstract In fractured reservoirs, data directly related to fractures are scarce and uni-dimensional (i.e. cores and image logs). Other types of data are better distributed and have proved to be related to fracturing but only indirectly (e.g. lithology or large scale structure). In such reservoirs, however, one has to understand fracture distribution and behavior at the field scale. A methodology has been developed within TotalFinaElf to define the relationships of all sources of data to fracturing and to integrate them and compared to another independent published method. To that end, a systematic work flow which goes from 1D to 2D and from static to dynamic data has been defined and various technologies tested. A field case in North Africa is taken to illustrate this methodology. In this field, fracture data from image logs have been related to:production data; 3D seismic attributes (coherency, amplitude, structural curvature) and fault interpretation and strain; log data such as porosity, thickness and lithology index. The former type of data is used to understand the contribution of each fracture set to flow. The latter two types of data are used to better map fracture distribution at the field scale. Ultimately, this mapping is calibrated with the production data of the other wells where fracturing data are not available and is then used to validate the specific role of fracturing in this field. A better reservoir simulation and infill well planning can be subsequently achieved. Introduction Fractured reservoirs are by nature highly heterogeneous. In such reservoirs, fracture systems control permeability and can also control porosity. Fracture modeling is therefore a key development issue and requires an integrated approach from geology to reservoir simulation and well planning. The geometry (i.e. static model) of the fracture network is generally defined from well data (i.e. cores or image logs) using conventional structural geology techniques. Then, fracture permeability can be assessed by relating the fracture aperture to the fracture excess conductivity measured on electrical image logs and/or to critically stressed fractures within the present day stress field. However, it is the authors' opinion that such approaches can only give, in the best case, a relative estimate of the fracture permeability. A quantitative modeling of fracture flow behavior is therefore required (i.e. dynamic model). At the well scale, this can be done by constructing Discrete Fracture Networks (DFN) through which flow is modeled and which are matched to well test data. Ultimately, these models can help in determining the fracture parameters required in dual porosity / dual permeability reservoir flow simulation. However, if these DFN models are appropriate for reservoir sector models, their application to full field simulation is somewhat difficult since their extrapolation outside the well scale can be limited by the heterogeneous vertical and lateral distribution of the fracture networks. The modeling of the spatial distribution of fracturing at the scale of the entire field and its calibration to well data is the purpose of this paper.
- Europe (0.93)
- Africa > North Africa (0.61)
- North America > United States > Texas (0.28)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.86)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.48)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.48)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- (2 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 Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Abstract The Borg Field is a stratigraphic trapped field of a shallow marine beachline system in the Tampen area of the Northern North Sea. The 30 MSm oil field is currently being developed with 2 injectors and 2 producers as a satellite field to the adjacent larger Tordis and Gullfaks Fields. As a result of the Upper Jurassic play, more reserves are possible to add as satellite developments. The Borg Field proves the Upper Jurassic Volgian-Ryazanian syn-rift deposit to be economically favourable. In the hunt for reserve replacement this play is expected to be important in the Tampen area, but however increasingly harder to predict and locate. The presence and location of additional reserves has been integration of multi-disciplinary data. On the Borg Field pressure data acquired through RFT measurements in exploration wells indicated that the field was pressure depleted before production onset. By analysing pressure data from regional producing fields and exploration wells, this depletion is likely to be caused by production in the Statfjord Field to the Southwest. The oil migration into the Borg Field was interpreted to follow a route from the deep mature basin to the Statfjord Field and to the Borg Field along Upper Jurassic hanging-wall slumped and turbidite sand stones draped along the main Statfjord Fault. These were amalgamating with paleo-beachline sediments lining a restricted bay and finally connected to the Borg Field sandstone on the other side of the paleo-bay. These sand stones can be partially mapped on seismic data and are encountered in exploration / appraisal wells and forms the likely path of pressure communication between the Borg Field and the Statfjord Field. These oil traps have a stratigraphic nature and both the location and size of the reservoir sands are difficult to map location and size of directly from the seismic, however the sands can be of economically importance due to their close proximity to nearby producing fields. During seismic work on the Borg Field, a northern segment was observed detached from the southern segment by a fault zone. A paleo beachline and a delta fan could be predicted by seismic character and through AVO analysis these "seismic-geo-bodies" where likely to be "sand-filled". The Borg Field was initially test produced for 6 months. During this test an influx of pressure was seen when the pressure dropped below the Statfjord Field, verifying earlier observations of pressure depletion from Statfjord, now being an influx. From analytical analysis of these data, the magnitude of the influx where calculated depending on pressure difference between the 2 fields. Well test analysis indicated that an additional volume was present outside of the main Borg Field. Through data integration in a reservoir model and sensitivity testing through the history matching process the presence of an extra volume of 15 MSm was predicted. This volume should be located to the north, to match timing and pressure of a production RFT, which corresponds to the seismic and geologic model. In addition a pressure influx from the Statfjord field mimicked by a pseudo injection well was required in order to math the final build up periods. This prediction of volumes and location, has impact on the reservoir development of the southern segment, the timing and type of exploration / appraisal methods and possibly on infrastructure investment for the whole area. The seismic methods utilised where verified by pressure analysis and can now be used to find similar type of sediments outside of the area "seen" by the production test. Introduction Block 34/7, situated on the central-western side of the Tampen Spur on the Norwegian Continental Shelf, was originally developed by Saga Petroleum ASA until their acquisition on January 1 2000 by Norsk Hydro ASA.
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.86)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.54)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Tampen Area (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Lunde Formation (0.99)
- (54 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)
Abstract History of giant Romashkino field exploration and development includes more than 50 years. Huge information bases on its geologic structure and exploitation is accumulated by now. The field presents asymmetric uplift of areal extent about 100×100 km. Commercial oil inflows have been obtained from 18 horizons. Some differences in formation fluid characteristics are observed throughout the field. By present the field is divided into 21 independently developed areas. Initial division of structures was made under conditions of insufficient information and was adjusted later. In connection with uncertainty in geologic structure there might be crossflows between structures of contour division. These conditions make difficult modeling and monitoring of the whole field development. For conductance of geologic and hydrodynamic modeling we have determined the following main principles:structure-by-structure modeling of the field, uniform procedure principles for all being modeled structures, parallel modeling of main field elements - areas. At present 3D geologic and hydrodynamic models for 5 areas of Romashkino field are developed and used. This is more than 6000 wells. 3D models are being brought now into commercial operation, i.e. realization of idea for continuously operating models of areas, blocks and experimental sections. This is practically possible based on fiber-optics system of communication applied in the field, which ensures interaction of all company structures. This will enable to provide application of efficient technologies and software for solution of applied tasks to most number of users. Uniform monitoring of the whole field development as a complex of all areas will be provided upon completion of hydrodynamic modeling of all areas. Introduction Crude was discovered in the main oil-saturated Pashiyskian deposits of Devonian horizons in Romashkino field in 1948. Huge sizes and complex geologicalstructure of the field, limited financial resources and acute demand of the country for oil products during these years set the problem of creating new system of development. It was suggested in 1950 by a group of specialists guided by academician A.P.Krylov. The introduction of the new system - contour flooding - began from 1952 on three central areas (Minnibaevskaya, Abdrakhmanovskaya, Pavlovskaya) with total area of about 70 sq.km. This marked the beginning of the first in the world unique process of oil fields development. Itsmain principles were formulated in the 1-st general scheme (1956). Oil Field Development: Short Characteristic Romashkino oil field is a platform type multilayer one. Total area of oil saturated reservoir is about 4300 sq.km. Geologic cross-section of the field is formed by Devonian, Carbonian and Permian deposits of total thickness about 1500 m. Of this value 75% accounts for carbonate and 25% for terrigenous rocks. Of 18 commercial oil-bearing horizons, 7horizonsconsistofterrigenous reservoirs, and 11 horizons - with carbonate ones /1/. Oil pools of Pashiyskian D1 and Kynovskian D0 horizons are mainly exploited in the field, this makes 88.8% of all explored reserves of the field. Total thickness of Pashiyskian horizon D1 deposits varies from 15–20 to 50 m and more. In cross-section of the horizon up to 9 layers of reservoirs are determined, thickness being from 1–2 to 3–6 m, separated from each other by clay rocks. Fig.1 shows a small fragment of one of the field areas in the interval of terrigenous deposits. One can visually imagine the complexity of geologic structure of horizon, composed of 8 formations with multiple confluence zones. This makes further designing and monitoring of the field development very difficult. Producing deposits of layer D0 are characterized by areal banded occurrence of mainly latitudinal trend. Up to three interlayers are determined in the layer, total thickness up to 4 m. Layer D0lies in the middle part of Kynovskian horizon and is located predominantly in the north-west of the field. Strategically the whole infrastructure of the field operation was formed based on rates of exploration and development. New wells have been systematically completed and put on commercial production, regional geology has been adjusted. Based on recent general scheme of development, the field has been divided into 21 independently developed areas. Oil and gas production departments (NGDU) are created and included into single technological scheme. Main principles of development. More than 25000 wells have been drilled by the early 1999 on the territory of Romashkino field. The field oil production and oil production from the new wells is presented in Fig.2. Rates of drilling new wells have considerably decreased in recent years. At the same time enhanced oil recovery methods are actively used /2/. Main principles of development. More than 25000 wells have been drilled by the early 1999 on the territory of Romashkino field. The field oil production and oil production from the new wells is presented in Fig.2. Rates of drilling new wells have considerably decreased in recent years. At the same time enhanced oil recovery methods are actively used /2/.
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Romashkinskoye Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.94)
- North America > United States > Texas > Permian Basin > Yates Formation (0.94)
- (22 more...)
Abstract Since 1990, over 200 hydraulic fracturing treatments have been performed in the Hassi Messaoud field in northeast central Algeria resulting in an average production increase of 5 m3/hr (750 bopd). The success of the stimulation program in this Cambrian age sandstone formation resulted from improved field practices of treating open-hole and slotted liner completions, and from the use of state-of-the-art fracturing equipment and engineering tools. After several years of production, the production rates of some fractured wells have declined due to several reasons: reservoir depletion, salt precipitation from formation water breakthrough or injection water breakthrough, and fracture conductivity damage due to barium sulfate scale and asphaltene deposition. Since 1996, re-fracturing treatments have been conducted on nine wells in order to restore production by placing another propped hydraulic fracture in the same target drain. The three case histories presented show exceptional, normal and marginal responses to the re-fracturing treatments. Explanations for the observed responses are presented and recommendations for the selection of new re-fracturing candidates in the Hassi Messaoud field are presented. Introduction The Hassi Messaoud oilfield, one of the giant oil fields of the world, is a thick sandstone reservoir in the northeastern part of central Algeria (see Figure 1). The field was discovered in 1956 and covers an area of approximately 2000 km. Currently, the field has around 1000 wells. Figures 2 and 3 show a map of the field and a typical cross-section with the different productive horizons (drains) as found in the field. Hydraulic fracturing has been used as a technique to increase production of the oilfield since the early 1990s. Historic overviews of hydraulic fracturing activities have been presented in papers by McGowen et al. and by Bouazza et al.. A significant amount of oil currently produced from the Hassi Messaoud field originates from wells that were hydraulically fractured. This is illustrated in Figure 4. At the end of 1999 proppant had been placed in approximately 200 wells in the field while injection tests had been conducted on approximately 250 wells. Figure 4 also illustrates that the production starts to decline as the number of fracturing treatments decreases. The main reason for the decrease in number of treated wells is the difficulty in selecting new candidates for hydraulic fracturing. The papers by McGowen et al. and by Bouazza et al. also give overviews of the production results of the treated wells. The fractured wells were divided into five categories, based on the results of decline-curve analyses:Wells with normal decline Wells with steep decline Wells with slow clean-up. Wells with zero rate. Wells with unstable production behaviour. It was anticipated that re-fracturing some of the wells in categories 1 to 3 could potentially restore some of the declined production. Since 1996, re-fracturing treatments have been conducted on nine wells in the Hassi Messaoud field. There have been other wells that have been treated more than once, but the target drains were different in the different treatments. Strictly spoken these treatments can not be considered re-fracturing treatments if the target drains were not hydraulically fractured before.
- 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)
- (23 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract The evolution of physico-chemical EOR methods in Russia is connected with the use of oil-displacing systems capable to retain and to self-regulate a complex of colloidal-chemical properties optimal for the purposes of oil displacement. The dominating role belongs to EOR technologies increasing conformance by flooding or by steam-heat treatment. Promising are such physico-chemical methods, in which heat energy of the formation or that of the injected heat carier is used to generate in situ alkaline buffer systems and CO2, as well as to form gels capable to increase oil displacement and conformance. Hydrolysis, hydrolytic polycondensation and coagulation processes proceeding in the system carbamide - aluminium salt - surfactants - water are used to prepare inorganic gels. To prepare thermoreversible polymer gels one uses solution - gel phase conversion in the system cellulose ether with a lower critical dissolution point - water. Presented are the results obtained on the employment of physico-chemical EOR technologies, developed at the Institute of Petroleum Chemistry SD RAS, in the oil fields of Russia. The tehnologies proved to be effective and ecologically safe. The period of payback is 5–12 months. Introduction More than 80 % of oil fields in West Siberia belong to Jurassic and Cretaceous deposits, which include low permeable terrigeneous reservoirs of a porous and porous-fractured type. At present similar oil fields are usually developed by flooding. For about 30 years EOR methods are employed in oil fields of West Siberia. One distinguishes two aspects in the problem of oil recovery factor (ORF) increase, i.e. to increase an oil displacement factor and to increase a conformance factor. The main conclusion obtained in the practice of EOR methods employment is as follows: the methods increasing conformance by the injected fluid proved to be the most successful. EOR methods increasing only an oil displacement factor failed to be effective, for example, the injection of low concentrated solutions of surfactants and other chemical reagents. At the same time EOR methods increasing a conformance factor or both factors produced positive technological and economic effect at any action mechanism. Such EOR methods include: injection of high concentrated solutions of surfactants and surfactant based systems, viscous-elastic and gel-forming thermoreversible polymer and dispersed polymer systems, gas, emulsions and foams, as well as generation of similar systems in situ. EOR methods employing surfactants and alkaline buffer systems In the course of physico-chemical EOR methods evolution one can clearly follow a tendency to provide an oil-displacing fluid with self-regulation elements, which allow fluid to function for a long period of time in the formation. Institute of Petroleum Chemistry, Siberian Division of the Russian Academy of Sciences (IPC SD RAS) has realized one of the variants of such a tendency. It is based on the ideas about the oil-displacing fluid as a physico-chemical system with a negative feedback. These ideas formed the basis for the development of physico-chemical principals to choose surfactant solutions taking into account thermodynamic and kinetic parameters for the system oil - rock - aqueous phase, affecting oil displacement from a porous medium. Proposed were alkaline buffer systems with a maximal buffer capacity ranging from 9.0 to 10.5 pH to provide negative feedback in oil-displacing IkhN systems, which allow the system to retain and self-regulate a complex of colloidal-chemical properties being optimal to oil-displacing purposes [1]. A characteristic property of the system is as follows: the system components are a constituent part of geochemical cycles of nitrogen, carbon and oxygen. It provides their ecological acceptability and multi-functioning: the components serve as a nutrient source for aboriginal formation microflora [2] and as natural tracers for filtration flows in oil reservoirs etc.
- Europe (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.68)
- Europe > Russia > Siberian Federal District > Tomsk Oblast > West Siberian Basin > Mayskoye Field > Tyumen Formation (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Uryevskoye Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Talinskoye Field (0.99)
- (5 more...)
Abstract The paper reviews oil recovery improvement for black oil fields with low bubble point pressure, which are developed under waterflood. The Kogalym field, located in Western Siberia, is approximately 2,400 meters true vertical depth, and produces from Cretaceous and Jurassic sand deposits. The black oil system has a bubble point pressure of 8.5 Mpa, less than 35 % of the initial reservoir pressure of 123.7 MPa. The optimal development strategy of such reservoir depends on selecting water flood elements, well pattern and flood pressure. The focus of this work is to justify an optimal waterflood pressure. In 1997–98 numerical simulation was performed on a separate waterflood pattern. A representative geological model of the pattern was constructed on the basis of comprehensive core analysis data from the well # 1037. Several development strategies were tested on the ECLIPSE model for various waterflood pressures: 24, 19 and 15 MPa. The maximum oil recovery factor (ORF) was obtained with a waterflood pressure of 15 MPa. The most economic case was with a waterflood pressure of 19 MPa. This pressure of 19 MPa is the optimal value of waterflood pressure, which is 75% of the initial reservoir pressure and exceeds the bubble point by more than 10 MPa. The analysis of the Kogalym field development for the last four years confirms these conclusions. Introduction The main method of oil production in Western Siberia is secondary recovery via waterflooding. Typical area reservoir development plans commence waterflood operations at initial conditions (Ref.1). This has been justified experimentally because of the increase of oil displacement factor with pressure. Early and intensive waterflooding provides high oil rates. This boost in production is favorable for cash flow and quicker payout. In the longer term, oil recovery losses due to low primary recovery and low sweep efficiency while waterflooding affects overall economics. The Kogalym field is being developed differently. The effective development strategy of the reservoir with low bubble point pressure depends on the selecting an optimal flood pressure. The focus of the work is to determine an effective strategy for the field, justified it by means of numerical stimulation and analyse practical results. Geological Prerequisite The Kogalym field produces from Cretaceous and Jurassic sand deposits. The main Cretaceous zone, BC11–2b, makes about 90% of the field total production and is the focus of this study. The pool has an impermeable boundary on the west due to a facies change from sandstone to shale, and is bounded by a limited aquifer on the east (See the Fig.1 and 2). The reservoir had a normal pressure gradient at the initial conditions. The vertical and horizontal heterogeneity averages a permeability of 50 mD and a porosity of 19%. The pay zone consists of up to five main sands subdivided with shale layers, which have an areal extent from several hundred meters to several kilometers in length (Ref.2). The vertical heterogeneity is presented in the geological cross section on Fig.2. Lithologically, the sands vary from highly permeable (up to 800 mD) to low permeability (less than 5 mD). The low permeable sands have a high content of sub capillary porous channels filled with connate water (Ref.3). This results in specific phase permeability for water given on the Fig. 4. The waterflood sweep efficiency of such reservoir should be low. The BC11–2b oil has a low bubble point pressure of 8.5 Mpa, (35% of the initial reservoir pressure) as determined from representative PVT analysis and confirmed by the field data. This low bubble point should allow pressure depletion to play a role in the overall recovery factor.
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.96)
- North America (0.88)
SUMMARY The Naricual formation of the El Furrial field is a deep anticline oil reservoir. It was originally highly overpressure and the reservoir temperature was quite high. The medium-type crude oil has a large asphaltene content and the fluid properties change significantly with depth. The field is sealed off from the underlying aquifer by a 200 feet tar mat. The primary production mechanism is fluid and rock expansion. A major data collection campaign for reservoir definition was set up right from the start of production. It resulted in a pressure maintenance programme whose objectives were the acceleration of oil production and the maximisation of the oil recovery and profitability. The pressure maintenance project and the enhanced recovery methods that have been implemented were based on 400,000 barrel/day water injection, later to be increased to 550,000 barrel/day and 450 million standard cubic feet per day of miscible gas injection. Together with the primary recovery these projects were estimated to produce 3,210 million barrel oil, and increase the oil recovery by 33 % of the original oil in-place. An integrated reservoir management and a continuing actualisation of the reservoir model was required from the start. As an illustration, the geological model was refined eight times during the past 13 years and the ongoing exploitation plan was adjusted accordingly. Its implementation required flexibility of facilities and production operations. This paper describes the field monitoring techniques of the water and gas injection. Tools and methods used to improve production and injection patterns have also been addressed. The application of resins, emulsions and diverting agents to control production and injection was excluded mainly due to the extreme reservoir conditions. Sand plugs have been set and intervals have been re-perforated with the aim of obtaining a more uniform injectivity and productivity. Their success ratio exceeded 70 %. Finally, the paper provides information on current studies, whose short term implementation could lead to produce up to 55 % of the original oil in-place. Introduction El Furrial is an onshore field located 470 km East of Caracas, the Venezuelan capital. The field was discovered in March 1986 by the exploration well Ful-1X (Figure 1). The well tested 7,311 barrel/day of 26.5°API oil on a 1/2 inch choke from an interval at 13,690 feet. The producing gas/oil ratio was 988 scf/barrel, the reservoir temperature 295°F and the original reservoir pressure was 11,250 psia at the reference level of 13,800 feet. One of the subsequent wells, Ful-4, proved oil in the underlying Cretaceous-01 formation. The Naricual and Cretaceous formations are separated by a 90 feet shale layer. The appraisal wells confirmed the anticline structure and classified El Furrial amongst the giant fields of the world. Information gathered from the early wells showed an important variation of the crude density with depth: the oil contained up to 13 % asphaltene and asphaltene flocculation occurs at pressures below 6,000 psia. The associated gas from the basal zone contained up to 2000 PPM H2S. The reservoir pressure declined initially by 17.7 psi per million barrel produced.
- Europe > Norway > Norwegian Sea (0.24)
- South America > Venezuela > Capital District > Caracas (0.24)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.44)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.51)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.34)