The geology and geophysics of the Ekofisk Field waterflood

Successful waterflooding of Ekofisk Field will enhance recovery of the total oil-in-place, producing an extra 170 mm barrels of oil. Monitoring, matching and predicting the reservoir performance will be performed with a complex reservoir model of 7700 cells.The chalk reservoir sequence at Ekofisk is multilayered with each layer exhibiting distinct thickness, porosity, permeability and water saturation trends. The upper part of the Tor Formation is one of those layers with imbibition characteristics suitable for waterflooding. Overlying the Tor Formation is the Ekofisk Tight Zone, a thin layer of low but variable permeability and porosity which generally acts as an hydraulic barrier.This geological and geophysical model provides a data set for the required complex reservoir model.     

Geology of the Edda Field Reservoir

The Edda Field, which was discovered in 1972, is located in the southern part of the Norwegian Sector of the North Sea. As in the nearby Ekofisk Field, chalk reservoir in the Danian (Lower Paleocene) and Maastrichtian (Upper Cretaceous) contain oil which originated in the Upper Jurassic organic rich shale sequence. A 15 slots drilling-production platform was installed on the basis of the results of 3 exploration appraisal wells. Seven producer wells were drilled and completed in 1979 and a production peak of about 33000 BOPD was reached in January 1980. All the development wells encountered less yield than expected and the 3 wells drilled on the southern flank of the structure were dry. Most of the characteristics of the chalk reservoir were known at that time but the existence of a pre-Maastrichtian paleo-relief in that area had not yet been established. This paleo-feature, the Lindesnes Ridge, strongly influenced the distribution and characteristics of the reservoir. Variation in initial porosity is the result of changes in sedimentation mode and rate as well as differential early cementation and mechanical compaction over the paleo-high. Differential porosity preservation is partly due to progressive infill of the trap by hydrocarbons but, as in most chalk fields, overpressure in the porous chalk layers was an important prerequisite.     

Spatial variability in petrophysical properties in Upper Maastrichtian chalk outcrops at Stevns Klint, Denmark

The spatial variability of porosity and permeability was determined for a section in the uppermost Maastrichtian chalk exposed in the Sigerslev quarry at Stevns Klint. The aims were threefold: (1) to quantify the spatial variability pattern and its link to geology by applying systematic variogram analysis procedure, (2) to detect potential cyclicity in the petrophysical properties in this pure and overtly homogeneous chalk, and (3) to compare the section with chalk reservoirs in the North Sea in order to asses to what extent this onshore sequence has a potential as an analogue of the offshore, more deeply buried chalk reservoirs. The interval is of comparable stratigraphic age to the uppermost reservoir zones in the Tor Formation of the North Sea chalk reservoirs. The variability and spatial correlation of porosity and permeability in both horizontal and vertical directions are interpreted in a geological context and show indications of small-scale heterogeneity at 15–25 cm scale, but the clear cyclic layering described from other chalk deposits is not recognised at this locality. The investigated outcrop is not a close analogue to North Sea reservoir chalk, but some aspects are common including basic material properties, porosity/permeability trends and the variability pattern. The outcrop has a potential as analogue for some of the onshore subsurface chalk successions at shallow burial depth that form important aquifers.     

Chalk fields along the Lindesnes Ridge, Eldfisk

Eldfisk field lies on the Lindesnes Ridge northwest of the Valhall and Hod fields and to the southeast of Edda in Block 2/7 of the Norwegian North Sea. The field has a complex geological history and reservoir geometry. Seismic reflection data is strongly gas affected and degraded over the majority of the field. The geological model of the field was based exclusively on well data and the model was inadequate to explain some of the production characteristics or to identify additional prospective well locations. In 1982 a programme of Vertical Seismic Profiling (VSP) was started in the northern part of the field. The seismic data provided by VSP have improved and confirmed the geological model, provided some explanations for production variances and identified further areas of interest.     

Seismic and well logging interpretation for evaluation of the lower Bahariya reservoir,southwest Qarun (SWQ) Field,Gindi Basin,Egypt

This paper focuses on seismic and well log interpretations for evaluating the sandstones of the Cenomanian Bahariya Formation in the southwest Qarun Field, Gindi Basin, northern Western Desert of Egypt. The seismic profiles display a clear anticlinal structure intersected by reverse faults in the study area. This faulted anticline has been interpreted to be one of the Syrian arc system folds formed by Upper Cretaceous tectonic inversion, which resulted from the NW movement of the African Plate relative to Laurasia. This anticline has been recommended as a target for exploration by the present work as it may represent a structural trap for hydrocarbon accumulation. The sandstones of the Lower Bahariya Formation in the southwest Qarun Field display good reservoir characteristics. The interpretation of the available well log data for the SWQ-21 and SWQ-25 wells for the Lower Bahariya Formation reflects a good reservoir quality for oil production in its topmost part. This reservoir possesses low S_W (<50%), high porosity (16%), low S_W/S_XO and low BVW (<0.09) which all reflect a high potential for oil production.     

川西坳陷中段沙溪庙组天然气成藏条件分析

探讨川西坳陷中段沙溪庙组天然气成藏地质条件,为油气勘探提供理论依据。从油气的烃源条件、储集条件、保存条件及成藏组合方面入手,结合构造史以及岩心、地震及钻井等资料进行分析,结果表明川西坳陷中段处于生烃坳陷中心地带,烃源岩丰富,具备生烃能力。晚三叠世中、晚期发育冲积扇—河流沉积相带,储集条件良好,后期构造运动使断层裂缝系统较发育,有利于储集条件改善和油气富集。其上有压力封存箱和巨厚的砂泥岩互层,保存条件良好。川西坳陷中段新场—盐亭地区近EW向古隆起及龙门山前缘扩展变形带中的鸭子河—石板滩地区是油气勘探的有利地带。     

琼东南盆地北礁地区梅山组丘形反射特征

目前琼东南盆地北礁凹陷中中新统梅山组顶部丘形反射引起广泛关注,但对其成因有不同认识。本文通过高精度二维、三维地震、钻井资料,研究丘形反射的特征。研究表明北礁地区梅山组顶部发育近东西向展布的长条形丘体,丘间为水道,丘内为中-弱振幅的地震反射,与西南部强振幅水道砂岩形成鲜明的对比,波阻抗反演揭示丘内为低波阻抗,属泥岩范畴。梅山组塑性丘内地层发生重力扩展,在其上覆的脆性地层（强振幅砂岩和弱振幅泥岩）发育多边形断层,反推出梅山组形成于深水环境,丘为泥丘,沉积环境分析也认为北礁凹陷中中新世为半深海沉积,梅山组的丘-谷分别对应上覆地层的谷-丘,认为是底流剥蚀/沉积成因。本文的研究对南海北部丘形反射的认识有重要意义,并可降低油气探勘风险。     

Inversion tectonics in Central Africa Rift System: Evidence from the Heglig Field

The Mesozoic-Cenozoic tectonic history of the Muglad Basin, is dominated by extension and inversion tectonics, but evidence of the inversion tectonics has not been well documented yet. In some other rift basins of CARS and WARS the phase of the inversion tectonics is well documented by several authors.This paper presents a structural study of the Heglig field area located on the eastern flank of the Muglad Basin. Detailed 3D seismic interpretation allows a better understanding of the structural style of the Heglig field. The new structural analysis has shown that the Heglig field has a complex structural framework reflected in the presence of a combination of two structural styles. The extensional structure is influenced by inversion tectonics during the Santonian time that creates four-way dip anticline structure, overprinted by the subsequent extensional movement that creates tilted fault block. The presence of inversion tectonics has supported by different means including seismic reflection, velocity, and source rock maturity data. The authors attributed the trapping of oil in the Lower Bentiu reservoir, that requires a horizontal seal, to the presence of the four-way dip anticline structure created by the inversion tectonics.The current interpretation of the Heglig field 3D seismic data sheds new light on the development and evolution of a key structure in the Muglad Basin. The results help to resolve long-standing discussion concerning hydrocarbon accumulation of the lower part of Bentiu Formation that lacks horizontal sealing.     

东海平湖油气田平湖组沉积相研究

平湖油气田是东海陆架盆地投入开发最早的油气田,平湖组是其主要的产层之一。长期以来,由于对平湖组沉积相认识一直存在分歧,影响了对其油气分布规律的认识。综合古生物、地化、岩心、录井、地震等资料,分析认为平湖组的沉积相为受潮汐作用影响的辫状河三角洲相,发育的主要微相类型包括有水下分流河道、河口砂坝、水下天然堤、分流间湾微相。这为油田下一步勘探开发提供了有益的指导。     

Is stress-insensitive chemical compaction responsible for high overpressures in deeply buried North Sea chalks?

Chalk compaction is often assumed to be controlled by a combination of mechanical and effective stress-related chemical processes, the latter commonly referred to as pressure solution. Such effective stress-driven compaction would result in elevated porosities in overpressured chalks compared with otherwise identical, but normally pressured chalks. The high porosities that are frequently observed in overpressured North Sea chalks have previously been reported to reflect such effective stress-dependent compaction.However, several wells with deeply buried chalk sequences also exhibit low porosities at high pore pressures. To investigate the possible origins of these overpressures, basin modeling was performed in a selected well (NOR 1/3-5) offshore Norway. This modeling was based on both effective stress-driven mechanical porosity reduction, which enables modeling of disequilibrium compaction, and on stress-insensitive chemical compaction where the porosity reduction is caused by thermally activated diagenesis.The modeling has demonstrated that the present day porosities and pore pressures of the chalks could be successfully replicated with mechanical porosity loss as the only process leading to chalk porosity reduction. However, the modeled porosity and fluid pressure history of the sediments deviated significantly from the porosity and pore pressure versus depth relationships observed in non-reservoir North Sea chalks today. To the contrary, modeling which was based on thermally activated porosity loss due to diagenesis (as a supplement to mechanical compaction), resulted in modeled chalk histories that are consistent with present day observations.It was therefore inferred that disequilibrium compaction could not account for all of the pore pressure development in overpressured chalks in the study area. The observation that modeling including temperature-controlled diagenetic porosity reduction gave plausible results, suggests that such porosity reduction may in fact be operating in chalks as well as in clastic rocks. If this is correct, then improved methods for pore pressure identification and fluid flow analysis in basins containing chalks should be developed.     

南海北部流花碳酸盐岩储层频域属性分析

生物礁碳酸盐岩油气藏储层具有丰度大、产能高的特点,一直以来是油气勘探重点探索的目标。南海北部大部分的油气发现均位于新近系,生物礁油气田也是该区勘探发现最大的亮点。其中东沙隆起区LH11生物礁是我国近年来发现的最大规模的同类型油气田。但其作为复杂的一类岩性油气藏,其非均质性和隐蔽性,使得在常规地震剖面上往往难以识别。本研究从地震频域属性角度出发,通过提取地震剖面频域图谱并结合测井孔隙度数据,分析生物礁储层频域特征,并结合正演模拟加以验证,认为研究区生物礁碳酸盐岩储层总体偏薄,导致了频率和衰减的异常,另外也证实薄层调谐效应方法可以较准确地估计层厚。     

Northstar-Geology,Exploration History,and Development Status,Beaufort Sea,Alaska

Exploration for oil at Northstar has been long and costly. Northstar leases were first acquired in 1979 at a joint state and federal sale by Shell Oil, Amerada Hess, and Texas Eastern. The Northstar Unit is 6 mi offshore and about 4 mi northeast of the Point McIntyre Field. Oil was first discovered in Shell's Seal Island 1 in 1983. Five additional appraisal wells were drilled (1983-1986) from two man-made gravel islands in 40 ft of water. Early engineering estimates put the cost of development at $ 1.6 billion. In February 1995, BP Exploration (Alaska) acquired a 98 % interest in the Northstar Unit from Amerada Hess and Shell Oil. When developed by BP, Northstar will be the first oil produced from federal leases in Alaska. To date, the oil industry has invested in excess of $ 140 million in exploration and appraisal operations. An additional $ 90 million was spent on lease bonus bids. The giant Prudhoe Bay and Kuparuk Fields lie along the Barrow Arch. This arch is bounded to the north by a rift margin that deepens into the present-day offshore region. Northstar is located among a series of down-stepping faults off this northern rift margin of the Prudhoe Kuparuk high. The structure is a gently south-dipping northwest-trending faulted anticline. The crest of the structure is located near 10,850 ft subsea. The primary reservoir is the Ivishak Formation (325 ft thick) of the Sadlerochit Group. This is the same primary reservoir at Prudhoe Bay, approximately 12 mi to the south. At Northstar the Ivishak is a high-energy, coarse-grained conglomeratic facies of the Ivishak Formation. The primary lithology is a pebbly chert to quartz conglomerate with occasional sandstone. This very high net to gross reservoir appears to contain no regionally continuous permeability barriers. Cementation has reduced primary porosity to less than 15 %. Accurate porosity estimates are difficult to make due to the coarse-grained nature of the lithology and the presence of kaolinite and microporous chert. Permeability is highly variable, but averages 10 to 100 mDarcies. Oil is a very light and volatile 42 API crude with approximately 2,100 ft3 of gas per stock tank barrel of oil. This oil is very different from the heavier oils (26) found to the south in Prudhoe Bay. Estimated recoverable oil reserves range from 100 to 160 million barrels. A free-standing drilling rig is required at Northstar because the reserves are beyond extended-reach drilling techniques from shore-based facilities. The current development plan is to expand the existing Seal Island to about 5 acres. This is significantly less than Endicott's 40-acre island. The proposed drilling and produc tion island will be accessed by summer barges and winter ice roads. Oil, gas, and water will be processed at a stand-alone facility and then sent to shore via a subsurface pipeline. Northstar will have the first Arctic subsea pipeline in Alaska to transport oil to shore facilities (TAPS). Preliminary tests in Spring 1996 were very successful in demonstrating the technology to successfully bury a subsea pipeline safely in the Arctic.     

Characterization of the Karababa-C reservoir in the South Karaku oilfield, southeast Turkey

The South Karaku oil field is located in southeast Turkey, and produces, from the Late Cretaceous Mardin Group, carbonate reservoirs consisting of the Karababa, Derdere, Sabunsuyu and Areban Formations. The Karababa Formation is divided into three members, of which the productive Karababa-C member, discussed here, is composed of shallow marine bioclastic mudstone to wackestone. It is affected by early to late diagenetic processes that caused modification of the original pore system by cementation, dissolution and fracturing. Two petrophysical-petrologic facies can be discriminated by principal component analysis, and linear, multiple and stepwise multiple regression analysis of petrophysical data. These correspond to vuggy-moldic porosity and microporosity dominated reservoirs.     

Origin of the hydrocarbon gases carbon dioxide and hydrogen sulfide in Dodan Field (SE-Turkey)

Gas occurrences consisting of carbon dioxide (CO₂), hydrogen sulfide (H₂S), and hydrocarbon (HC) gases and oil within the Dodan Field in southeastern Turkey are located in Cretaceous carbonate reservoir rocks in the Garzan and Mardin Formations. The aim of this study was to determine gas composition and to define the origin of gases in Dodan Field. For this purpose, gas samples were analyzed for their molecular and isotopic composition. The isotopic composition of CO₂, with values of −1.5‰ and −2.8‰, suggested abiogenic origin from limestone. δ³⁴S values of H₂S ranged from +11.9 to +13.4‰. H₂S is most likely formed from thermochemical sulfate reduction (TSR) and bacterial sulfate reduction (BSR) within the Bakuk Formation. The Bakuk Formation is composed of a dolomite dominated carbonate succession also containing anhydrite. TSR may occur within an evaporitic environment at temperatures of approximately 120–145 °C. Basin modeling revealed that these temperatures were reached within the Bakuk Formation at 10 Ma. Furthermore, sulfate reducing bacteria were found in oil–water phase samples from Dodan Field. As a result, the H₂S in Dodan Field can be considered to have formed by BSR and TSR.As indicated by their isotopic composition, HC gases are of thermogenic origin and were generated within the Upper Permian Kas and Gomaniibrik Formations. As indicated by the heavier isotopic composition of methane and ethane, HC gases were later altered by TSR. Based on our results, the Dodan gas field may have formed as a result of the interaction of the following processes during the last 7–8 Ma: 1) thermogenic gas generation in Permian source rocks, 2) the formation of thrust faults, 3) the lateral-up dip migration of HC-gases due to thrust faults from the Kas Formation into the Bakuk Formation, 4) the formation of H₂S and CO₂ by TSR within the Bakuk Formation, 5) the vertical migration of gases into reservoirs through the thrust fault, and 6) lateral-up dip migration within reservoir rocks toward the Dodan structure.     

Reservoir quality along a homoclinal carbonate ramp deposit: The Permian Upper Dalan Formation,South Pars Field,Persian Gulf Basin

Permo-Triassic carbonate successions host some of the largest oil and gas reserves in the Arabian Plate, including the world's largest gas reservoirs of the Upper Dalan and the Kangan formations in the South Pars Gas Field, Persian Gulf Basin. Both formations are stratigraphically equivalent to the Upper Khuff Formation which has been long recognized as a major oil and gas reservoir in the Arabian Peninsula. The Permian Upper Dalan Formation is composed mainly of mixed carbonate-evaporite sequences that formed on a laterally continuous homoclinal carbonate ramp with significant variations in reservoir heterogeneity and quality. They can be grouped in 18 microfacies. High reservoir qualities are found within high-energy shoal environments with a tendency of the best reservoir quality to occur towards the basin in a mid-ramp setting. In contrast, low-energy tidal flat environments exhibit the poorest reservoir quality. Reservoir quality from lagoonal environments is diverse. Diagenesis has significantly affected reservoir properties by both enhancing and destroying original porosity and permeability. Bivariate plots of porosity and permeability values, combined with thin section petrography indicate that pore-filling “pervasive” and poikilotopic anhydrite cements had the greatest negative impact on the reservoir quality whereas dolomitization and dissolution of grains and cements played the most positive role. Two third-order sequence stratigraphic cycles link lithologies and depositional environments to sea-level fluctuations. HSTs are associated with better reservoir characteristics than TSTs.     

西湖凹陷中-下始新统宝石组油气地质与勘探潜力

西湖凹陷是东海陆架盆地油气勘探潜力最好的凹陷之一。通过西湖凹陷宝石一井中下始新统宝石组井震资料,厘定了影响油气资源计算结果较大的关键参数,如烃源岩厚度、有机质油气产率、排聚系数等;建立了构造、沉积、孔隙度与油气生、运、聚模型,编绘了西湖凹陷宝石组生油岩厚度图、有机碳、Ro、生油气强度等值线图;采用BASIMS 4．5盆地综合模拟系统重现了西湖凹陷宝石组的地史、热史、生烃史、排烃史和运聚史,分析了宝石组空间展布特征与生、储、盖、圈、运、保等地质条件,提出并建立了宝石组合油气系统。利用多种方法定量计算的宝石组生烃量和资源量与西湖凹陷已证实的主力烃源岩系平湖组相似,认为宝石组是西湖凹陷又一重要烃源岩及油气勘探目的层系,拥有巨大的油气勘探潜力。     

Oolitic shoal complexes characterization of the Lower Triassic Feixianguan Formation in the Yuanba Gas Field,Northeast Sichuan Basin,China

The Yuanba Gas Field is the second largest natural gas reservoir in the Sichuan Basin, southwest China. The vast majority of the natural gas reserve is from the Permian Changhsingian reef complexes and Lower Triassic Feixianguan oolitic shoal complexes. To better understand this reservoir system, this study characterizes geological and geophysical properties, spatial and temporal distribution of the oolitic shoal complexes and factors that control the oolitic shoals character for the Lower Triassic Feixianguan Formation in the Yuanba Gas Field. Facies analysis, well-seismic tie, well logs, seismic character, impedance inversion, and root mean square (RMS) seismic attributes distinguish two oolitic shoal complex facies – FA-A and FA-B that occur in the study area. FA-A, located in the middle of oolitic shoal complex, is composed of well-sorted ooids with rounded shape. This facies is interpreted to have been deposited in shallow water with relatively high energy. In contrast, FA-B is located in flanks of the oolitic shoal complex, and consists of poorly sorted grains with various shape (rounded, subrounded and subangular). The oolitic shoal complexes were mainly deposited along the platform margin. From the early Fei 2 Member period to the late Fei 2 Member period, the oolitic shoals complexes on the platform margin gradually migrated from the southwest to the northeast with an extent ranging from less than 100 km²–150 km² in the Yuanba Gas Field. The migration of oolitic shoals coincided with the development of a series of progradational clinoforms, suggesting that progradational clinoforms caused by sea-level fall maybe are the main reason that lead to the migration of oolitic shoals. Finally, this study provide an integrated method for the researchers to characterize oolitic shoal complexes by using well cores, logs, seismic reflections, impedance inversion, and seismic attribute in other basins of the world.     

饶阳凹陷潜山油气分布特征及富集规律

饶阳凹陷是冀中坳陷潜山油气勘探的重点地区之一。综合应用现代油气成藏、地球物理、地球化学等理论和方法,对饶阳凹陷潜山油气成藏的地质条件进行了分析。结果表明,该区带油源丰富,储集条件好,发育多套有效的储盖组合,各成藏要素时空配置良好,具有形成大规模油气田的有利条件。根据已发现油气藏构造特征、成藏条件及油藏类型得出,研究区油气藏集中分布于潜山顶、潜山坡及潜山内幕。在此基础上,提出了潜山油气藏多分布于近源的断裂带附近,水动力承压区、深凹陷、古隆起的叠置区,断棱、峰顶、内幕高点等位置的油气富集规律。     

应用合成地震记录确定南黄海北部盆地中生代地层的分布

黄海海域是我国近海目前唯一尚未获得商业性油气发现的海域,海域内发育了3个中新生代含油气盆地,目前已在北部盆地中生代泰州组地层中发现了油气显示。过去由于受资料所限,对盆地的油气资源评价,多关注于第三纪盆地,忽视了中生代盆地的油气资源远景。作者通过对南黄海北部盆地已钻遇中生代泰州组地层的钻井和过井数字地震剖面的追踪对比,结合4km×8km地震测网和重、磁资料综合解释,认为中生代盆地同样具有良好的含油气远景,特别是盆地的东北凹,中生代地层沉积厚度大,分布范围广,具有较好的油气资源远景。