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Collaborating Authors
Reservoir Characterization
Simulation of Black Oil Reservoir on Distributed Memory Parallel Computers and Workstation Cluster
Ma, Zhiyuan (China National Offshore Oil Corporation) | Jing, Fengjiang (China National Offshore Oil Corporation) | Xu, Xiangming (Computing Center, Academia Sinica) | Sun, Jiachang (Computing Center, Academia Sinica)
Abstract This paper describes parallel linear solvers of LSOR and preconditioned ORTHOMIN (K) on parallel computer based on T800 Transputers and SUN workstation cluster (with Ethernet network). Both Algorithms show a high degree of parallel efficiency on Transputers, whereas only full implicit method and large petroleum reservoir problems can observe a high efficiency on SUN workstation cluster. The key issue in parallelization of reservoir simulator on workstation cluster is the improvement of communication speed. Introduction Petroleum industry is among those that first introduced computer technology, and is also the area where computer technology is adopted thoroughly and popularly. Reservoir simulation is one of the most powerful tools for analysing the complicated fluid flow within a reservoir today. Engineers frequently use reservoir simulation to find out production performance of entire reservoir, and work out development plans scientifically. Distributed memory parallel computer and workstation cluster are two hot spots in computer industry today. It is attracting more and more attention as how to use these computers to solve practical problems requiring large computation. Numerical reservoir simulation, requiring large computation and has relatively high degree of parallelism and modest I/O requirement, therefore the distributed memory parallel computer system is suitable for such purpose. But most existing reservoir simulators are based on sequential computers and must be restructured to make full use of the capability of these computers. P. 505
- Asia > China (0.29)
- North America > United States (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.42)
Abstract At the present time, field-scale reservoir simulations are usually carried out with Cartesian grids. However, the use of these grids does not permit a good representation of reservoir geological features and reservoir description. Different approaches have been investigated to overcome the disadvantages of Cartesian grids. The corner point geometry (distorted grids) is often used as an alternative for complex full-field studies. This approach can better adapt the grid to reservoir boundaries, faults, horizontal wells and flow patterns and is easily used in standard finite difference reservoir simulators. The key problems for this technique are the preservation of the accuracy of fluid flow modelling and well treatment. In this paper, we will present a technique well suited to the corner point geometry and discuss its application range. Results are presented for test cases, comparing different control- volume type approximations. Introduction In reservoir simulation, the use of rectangular grids associated with the standard finite difference method does not permit a good representation of reservoir geological features and reservoir description, especially for faults, cross stratified beds, heterogeneities and wells. Flexible grids, such as corner point geometry, triangular grids or Voronoi grids, can be used to improve the accuracy. Among these flexible grids, the corner point geometry is the most used with the advantage of easy implementation in standard reservoir simulators and of CPU time gain due to regular matrix structure. The corner point geometry can represent complex reservoir geometries by specifying the corners of each grid block in grid building. It is well known that the use of the five-point scheme for distorted grids yields erroneous results. More accurate numerical schemes are needed with the ability to handle cross derivative terms. Several nine-point schemes, based on control volume methods, have been derived for distorted grids but no comparison is mentioned in the literature. These methods will be discussed in the paper and some examples are presented. In addition to the description of geological features, another major application of flexible grid is well modelling. However, as presented by Ding et al., caution should be used as regards the well region gridding. A sophisticated grid may not give better results if radial flow is not well approximated. In this paper, we will present the techniques for handling well in distorted grids, independently of the well location within the grid block. The technique of implementation in a 3-D reservoir simulator is also presented and some problems, such as heterogeneity modelling, are discussed. P. 451
- North America > United States (0.93)
- Europe (0.68)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.74)
Abstract X-ray computerised tomography (CT) has been increasingly applied in the study of rock properties and the in-situ monitoring of fluid displacements. Aseries of oil-water drainage-imbibition floods in laminated rock slabs have been performed in this laboratory. X-ray CT imaging techniques were used to evaluate the rock characterisation and to monitor the fluid saturation processes. This paper describes significant technical advances in X-ray measurement of fluid saturations in very heterogeneous rock slabs. Approaches to minimising the beam hardening effect and suppressing high-frequency artefacts are also described. A number of typical experimental results indicate that our improved CT techniques can be used to accurately evaluate the rock heterogeneity and its effects on fluid displacements. These include the distribution of porosity and permeability in a laminated aeolian sandstone, the distributions of irreducible water and remaining oil saturation, as well as oil recovery. CT measurements were checked and calibrated against probe permeameter and fluid mass balance measurements and excellent agreements has been obtained. At capillary-dominated conditions (low flow rate and unit ratio of water to oil viscosity), the average remaining oil saturation is around 35–40 % of OOIP. For flow across lamina, about 30–55% of the original oil was trapped in the upstream regions of low permeability layers due to the interaction of capillary forces with the lamination. For flow along lamina, the capillary trapping is reduced but flow bypassing results in similar levels of oil retention. The distributions of remaining oil saturation and oil recovery across lamination shows clear variations related to the local permeability and the initial oil saturation. By incorporating the detailed petrophysical analyses into a simulation model, an excellent match of experiments with numerical simulation was obtained both for cross-lamina and along-lamina flows. These findings have important implications for the determination of field-wide residual oil saturation from core plug measurements. Introduction As a relatively new technique, X-ray computerised tomography (CT) has been increasingly applied in the study of rock characteristics and the in-situ observation of coreflood displacements during the last decade. Generally, medical X-ray CT scanners have been employed due to their availability and relative ease of use. X-ray attenuation differences as small as 0.1% can be measured accurately at a resolution of 2 mm or less. The measurements can be completed in seconds and can provide high quality 2D images with quantitative data for use in petrophysics and reservoir engineering.
- North America > United States (0.68)
- Europe (0.46)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract This paper discusses the design and application of the drilling and wellbore stability technology for an extended reach well drilled in the UK sector of the North Sea Central Graben Basin. The use of this technology can provide reservoir and development planners with an alternative means to economically and efficiently develop accumulations which are situated beyond conventional reach of drilling platforms. Very long reach drilling can enable developers to either defer or eliminate the capital spending associated with additional platforms and facilities or subsea development of satellite accumulations. The paper addresses several areas that include mud weight and mud system, rock mechanics aspects impacting wellbore stability. well path design, drill string, casing and cementing considerations. It gives a detailed discussion of how the safe operating window for the mud weight was predicted from stability analysis and used to successfully drill the South Everest Extended Reach well (SEER T12) to TD. The paper also describes the rock mechanics data, in situ stress and pore pressure analysis. and operational practices trying to maintain the desired equivalent mud weight within the safe operating range. Introduction This work originated with regard to a very long reach well drilled in the Amoco operated Everest Field. The Everest Field is part of a larger multi-field development in which several medium to small size gas-condensate accumulations, at a distance of 250 miles offshore of the UK, will be economically developed by sharing facilities and pipeline infrastructure created by Amoco and its partners (Central Area Transmission System-CATS). Everest Field consists of multiple accumulations spread over a wide geographic area and two production platforms situated in the northern and southern ends of the field are included in the development plans. Initially the north end of the field would be developed with the development of the southern end to occur at a later date. During the development of North Everest, a very long reach well was conceived. which would be drilled from the North Everest platform at a lateral displacement of over 4 miles to reach the South Everest accumulation. This would defer construction of over $200 millions second platform and accelerate production. This well has been successfully drilled yielding a positive impact on project economics. The sail angle in this well reached 76 degrees by 5,300 ft measured depth. This angle was held resulting in a total displacement of 20,966 ft, a measured depth of 24,670 ft, and a 9,079 ft TVD, as shown in Fig. 1. The formation drilled was weak shale from surface to 8,000 ft TVD and shale/sandstone below to a Paleocene sandstone target at 8,900 ft. The paper describes the key decisions, based on application of wellbore stability technology and associated rock mechanics study, which led to successful drilling of this South Everest Extended Reach (SEER T12) well. One of the most important aspects of planning such wells is deciding the correct mud weight from the wellbore stability analysis. The mud weights has to be high enough to prevent hole collapse but low enough to prevent fracturing the weak shale and production section. The rock mechanics and stability considerations gave the drilling team the confidence to reduce mud weight used earlier in drilling the production section by over 1 lbm/gal, which avoided differential sticking problems. P. 587
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.78)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract Efficient field management and appraisal rely on a good understanding of reservoir geology and recovery efficiency. This requires co-operation and good communication between different disciplines. This paper presents and demonstrates the shared earth model approach, to encourage integration and co-operation between disciplines producing more reliable reservoir characterisation and performance prediction. A North Sea field is used as an example to illustrate the development and use of the shared earth model. The way in which it brings together the subsurface disciplines is shown by dynamic data feedback and seismic validation of simulator predictions. Introduction In the present state of the oil market, subsurface teams are under more pressure than ever before. Field appraisal and development time are being sharply decreased; waterflood and pressure maintenance schemes are designed very early in field life; and infill drilling programmes have to be operated within tight financial constraints. If subsurface teams are to make sound interpretations and predictions in little time, and also deliver the high recover factors which are now expected, the members need to work together, communicate and integrate their information much more thoroughly. One way to achieve this is through the shared ownership of a numerical description of the reservoir and its properties: this is the shared earth model concept which is discussed in detail below. In order to reach the degree of interdisciplinary collaboration which is increasingly needed in our subsurface teams, the lines of demarcation between subsurface technical disciplines must become indistinct. By doing this opportunities are created that did not exist before. Seismic validation of reservoir simulation is an example of this. This paper is in two parts: the first part discusses the shared earth model concept in subsurface integration; and the second part describes an application of this concept to a field in the North Sea, showing the advantage to be gained by integrating seismic modelling with reservoir simulation in the planning of an infill drilling programme. GEOSCIENCE AND ENGINEERING RESERVOIR MODELS Everyone in a subsurface team has a model of the reservoir on which they are working. Some models are numerical, such as a reservoir simulation model; others are graphical, such as a contour map or a well correlation diagram; and some models are conceptual, existing only inside the heads of geoscientists. P. 383
- Europe > United Kingdom > North Sea (0.88)
- Europe > Netherlands > North Sea (0.55)
- Geophysics > Seismic Surveying > Seismic Processing (0.69)
- Geophysics > Seismic Surveying > Seismic Modeling (0.51)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Lower Kimmeridge Clay Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/12a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/12a > Magnus Field > Kimmeridge Formation > Lower Kimmeridge Clay Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
SPE Members Abstract In 1981, ARCO executed the first offshore development contract ever between China and a Western oil company. In 1983, ARCO discovered the Yacheng 13-1 gas reservoir during exploration drilling in the South China Sea. Following several years of delineation drilling, reservoir evaluation, and commercial negotiations, a full field development program was initiated in 1992 to produce the field's estimated 3 TCF of gas reserves. This paper describes design processes, special engineering tasks, procurement decision making, and field procedures which were implemented to optimize cost and performance of oil country tubular goods (OCTG) for the development drilling program. Structural drive pipe casings were designed in an integrated manner with the drilling platforms. Conductor, surface and intermediate/production casings were optimized by identifying constraining loads and selecting specialized OCTG products to improve tubular design efficiency for those loads. Production liners and tubings were designed to provide metallurgical corrosion protection, standardized well programs, completion flexibility, and minimum cost. To further optimize liners and tubings, empirical collapse ratings were derived from a focused testing program. Connection qualification testing was conducted to maximize confidence in the premium connections and field running procedures. These engineering efforts resulted in significant reductions in tangible drilling costs and substantial increases in the field reliability of the OCTG. General Design Considerations As shown in Figure 1, the Yacheng gas development is located 60 miles south of Hainan Island and 480 miles southwest of Hong Kong in 300' water depths, The development, overviewed in [1], was optimized to minimize the number of wells, thus making production capacity and reliability of each individual well critical to meeting production obligations. Due to this remote location and the importance of production deliverability, wells are designed for long producing periods and minimum intervention. Figure 2 shows the development scenario involving two well platforms and a total of 12 wells, with the second platform planned some years after initial production is established from the first platform. The two independent development platforms allow for optimized reservoir drainage, reduced costs by limiting well departures, and greater flexibility for responding to future drilling needs in the life of the field. The final number and placement of wells will be determined based on ongoing refinement of reservoir and production information. Pore pressure and fracture gradients in the Yacheng area have been established through the eight (8) previously drilled exploration and delineation wells. Figure 3 shows the pore pressures, fracture gradients, and mud weights estimated for the Yacheng development wells. Normal pressures were predicted to depths of 8,000' to 9,000'. A transition zone is then encountered with geopressuring resulting in shale pore pressures as high as 13.8 ppg in the interval from 9,500' - 10,500' and mud weight is increased accordingly. A pressure reversal below 11,500' occurs in the reservoir section to 8.5-9.0 ppg equivalent. Geothermal temperatures in the Yacheng area, and the South China Sea in general, are high relative to other operating areas. Figure 4 shows the estimated geothermal gradient based on log data from the various wells drilled in the area. Downhole temperatures reach 400 F near 15,450', resulting in a linear geothermal gradient of 2.27/100' with a 50 F sea floor temperature. Normal production rates range from 40-60 MMSCFPD with gas chemistry of 84% methane and 11% CO2 with up to 50 ppm H2S. Flowing wellhead temperatures range from 200 F to 302 F. Water production was estimated to be less than 50 BPWD, but could increase to 1,200 BWPD with Chlorides of 11,000 ppm. These conditions required the use of 13Cr metallurgy for production liners and tubings. Based on the described pressure regime and previous drilling experience, casing setting depths were chosen. Drive pipe would be driven to refusal in the range of 300'. Conductor casing would be set near 1,400' TVD. The 13.3/8" surface casing would be set in in the range of 5,800' TVD. P. 355
- Asia > China (1.00)
- North America > United States > Texas (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Asia > China > South China Sea > Yinggehai Basin > Yacheng 13-1 Field > Yanan Sag Formation (0.99)
- Asia > China > South China Sea > Yinggehai Basin > Yacheng 13-1 Field > Yacheng Formation (0.99)
- Asia > China > South China Sea > Yinggehai Basin > Yacheng 13-1 Field > Sanya Formation (0.99)
- Asia > China > South China Sea > Yinggehai Basin > Yacheng 13-1 Field > Lingshui Formation (0.99)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
SPE Member Abstract The remote, desert location of the Cooper-Eromanga Basin in central Australia provides an ongoing challenge to maintain cost effective operations and development. The uniqueness comes from the lack of regional infrastructure typical of similar, mature, remote, onshore operating provinces in the USA and Canada, the large scale and sparseness of the operations, and the harshness of the arid environment. It is hoped this paper will provide insights to operating in remote locations, including the inland basins of China. Operating costs have been reduced in real terms and examples are given of the innovations and technologies being used to achieve continuous improvement. Benchmarking indicates lower costs to look-a-like areas in the USA/Canada; operating efficiencies offset the costs of additional infrastructure. The future will require additional cost reductions to avoid erosion of profitability due to declining oil volumes and increasing numbers of facilities. The key to success is in recognising the need for change and challenging every aspect of the operation. Gains are likely to come from a myriad of small improvements rather than a few large gains. WHERE IS IT? The Cooper and Eromanga Basins are large overlying basins of Permian/Triassic and Jurassic ages; they are located in central Australia, as shown in Figure 1. The landform is arid being on the edge of the Simpson Desert, flat with sand dunes and gibber plains, and subject to flooding from inland drainage. Nearest infrastructure is located 500 to 800 miles away at Adelaide, Brisbane and Sydney which provide the markets for produced gas.
- Oceania > Australia > South Australia (1.00)
- Oceania > Australia > Queensland (1.00)
- Oceania > Australia > South Australia > Cooper Eromanga Basin > Tirrawarra Field (0.99)
- Oceania > Australia > Queensland > Cooper Eromanga Basin (0.99)
- Oceania > Australia > South Australia > Eromanga Basin (0.94)
- (7 more...)
Abstract Jidong is a rather complicated fault-block oil producing area which is characterized by broken structures, multiple reservoir types, complicated oil-water systems, big lateral changes, deeply buried major oil layers, severe heterogeneity and varied fluid properties. In addition, more than 80% of the wells are directional due to the limit of surface conditions, which gives more difficulties to the development of Jidong area. Therefore Comprehensive study of multi-disciplines has been used in Jidong to improve early reservoir evaluation and development. Application of advanced technologies and theories such as production seismic, loggings, production tests, limit test, structural sedimentology, fine reservoir description, numerical simulation and contagious wells distribution has enhanced study of enrichment pattern of oil and gas. The strategy of progressive exploration and development has been adopted through "Integral plannIng, partial implementing, well-aimed studying, timely adjusting and gradual improving". Since 1989, the success rates of development wells has been over 95%. Introduction The complicated geological conditions in Jidong area have brought high risks to the development of the area. Therefore, combination of exploration and development to raise success rate of development wells becomes essential. In the mid of 1980s, conventional development design based on 2D seismic and the data of a few exploration wells have left lessons to us or instance in Gaoshanpu Oilfield, the middle and shallow reservoirs are complicated structural and lithologic small fault-block pools. The success rate of development wells was only 56%, with conventional one-time well distribution, which was roughly the same as that of appraisal wells. In order to improve the early reservoir evaluation, Varied advanced and practical technologies and comprehensive study of multiple information have been carried out since 1988 and success rates of development wells has been obviously improved. The development of complicated fault-block oil field depends on the study of oil-gas enrichment patterns, structure and fault system, reservoir distribution and reservoir types. The procedure of progressive exploration and development, also called APR (Aggressive-Progressive-Regressive principle), has been used in implementation of development program. P. 249
- Asia > China > Hebei > Bohai Basin > Liuzan Field (0.99)
- Asia > China > Hebei > Bohai Basin > Huanghua Basin > Gaoshangpu Field (0.99)
- Asia > China > Bohai Bay > Bohai Basin > Jidong Nanpu Field (0.98)
- North America > Cuba > Block L (0.93)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Generally, the reservoirs with permeability lower than 50×10–3 m2 is called low permeable oil field. Ansai oil field in which the average permeability is about l.29× 10–3 m2 is classified as ultra-low permeable oil field. Despite many low permeable reservoirs were discovered in early days, they haven't been effectively produced due to the complicated production technology and low profit. However, with the development of petroleum industry, the technologies of developing low permeable reservoirs have been improved, particularly, the progress of fracturing and water injection, the production of low permeable reservoirs has been rapidly developed. This paper aims to overview the reservoir, fracturing and water injection, describe the key methods used in production of Ansai ultra-low permeable reservoirs, including the results of water injection. Introduction Ansai oil field is located in the west of China. It was found in 1983.The oil-bearing series are placed in Yanchang group of Triassic system, including Chang 6, Chang 4+5, Chang 3 and Chang 2 layers. This is the largest integral oil field in Shan Gan Ning Basin up to now. The major oil reservoir named Chang 6 is at the depth of 1000 to 1300 m with the air permeability of 1.29×10–3km2(k=0.49×10–3 m2). So it is a typical ultra-low permeable, low pressure and production reservoir. There is no initial output when drilling in the oil reservoir with conventional mud. The formation productivity test shows that the production is below 0.3 to 0.4 t/d when drilling in oil reservoirs with unbalanced technique using oil-based mud or foam mud. After removing damage by conventional fracturing, the initial production is only 2 to 3 t/d and decrease to below 1.5 tons per day after half a year. Oil well is lack of fluid supply and intermittent pumping. The gas is escaped from the formation, wax and scale are seriously deposited in boreholes. So the pump efficiency is low. The surface environment is very complicated with inconvenient transportation. The production is difficult to manage. Because it is a marginal oil field, at the beginning of development, opinions vary to whether the production is efficient to obtain profit. In order to produce Ansai ultra-low permeable reservoirs efficiently, well group, pilot and industrialized test areas were opened to the study of reservoirs, oil reservoir production, completion, fracturing and water injection, so as to decrease drilling cost and greatly improve the effect of fracturing and water injection. The mechanical oil recovery, surface gathering and transportation and cluster drilling are matched. Ansai oil field has been put into industrialized development since 1990. At present, the average output of single well increases to above 4 tId from 1 to 2 t/d in water injected area. The plateau period has been up to 3 years. P. 227
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Mineral > Silicate > Phyllosilicate (0.46)
- Asia > China > Shaanxi > Ansai Field (0.99)
- Asia > Middle East > Israel > Central District > Southern Levant Basin > Gan Field (0.97)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract The Huizhou 21 – 1 oil field is one of the first offshore oil fields to be developed in the South China Sea. After start-up of production from HZ/2l- 1 in 1990, four adjacent oil fields have been developed and tied into the original infrastructure. The Huizhou Fields were developed and are operated by a joint venture between China Offshore Oil Nanhai East Corporation (CONHE) and ACT Operators Group, which is jointly owned by three Western oil companies (Agip, Chevron, Texaco). Even though oil prices have been much lower than originally forecasted, ACT and CONHE have been able to mitigate the impact of lower oil prices on the financial performance of the Huizhou Fields. This is due to better - than - expected reservoir performance, continuous efforts to update and improve the development plan, and cost -effective integration of new fields into the existing infrastructure. This case study describes how the development plan has evolved and the continuous learning process that CONHE and ACT went through to optimize economic benefit. RESERVOIR PROPERTIES The Huizhou Oil Fields are located in the Pearl River Mouth Basin of the South China Sea. Five oil fields (HZ/2l-l, HZ/26-l, HZ/32–2, HZ/32 – 3, HZ/32 – 3 NE) are developed from four offshore platforms at a water depth of about 100 meters. The fields are simple anticlinal structures and are generally unaffected by faults. The location of the fields in shown in Figure 1. Several characteristic of the Huizhou Fields are interesting from a development perspective. The first is that the oil is contained in multiple stacked sands, at depths raging from 1900 to 3000 meters. P. 99
- Asia > China > South China Sea > Zhujiangkou Basin (0.99)
- Asia > China > South China Sea > Huizhou 21-1 Field (0.99)
- Asia > China > South China Sea > Pearl River Mouth Basin > Huizhou Field (0.97)