An offshore Abu Dhabi carbonate oil field which was discovered in 1969 and put on production in 1985. The field produces from a reefal limestone formation deposited in the middle cretaceous. The field is characterized by good reservoir properties in the rudest banks well developed in the northern part of the field. Soon after production starts, wells water cut gradually increased to reach 50% within 4-5 years with drastic decline in oil production. Horizontal drilling was implemented with an objective of increasing well exposure to reservoir, reducing drawdown and as such combating water coning/channeling phenomena. Although oil production from horizontal wells was substantially improved, water production trend and production decline, however, did not change in most of the cases. Reservoir heterogeneities, such as fractures and facies distribution, are believed to be main contributors to a water coning/ channeling phenomena and to the escalation of water production trends. Therefore, understanding of geological, petrophysical, properties of the formation is the corner stone for, controlling water production problems and hence improving reservoir performance. In this contest, the operating company decided in 2006 to acquire 3D seismic to improve the field imaging and embarked in intensive well data gathering program including, FMI, coring, VSP and PLT measurements to improves the knowledge about the reservoir. This paper will illustrate an integrated approach to build a 3D fracture model of Reservoir-A using a comprehensive full set of geological drivers obtained from seismic attributes, core and logs data which may control and explain the fracture occurrence in the reservoir. The model was used to enhance the history match accuracy and help also to assess new potential ideas for future development.
During the geological history, water borne bacteria may react with oil and result in the formation of tar (synonymous of bitumen in this paper). The dynamics of the reservoir over its history may also leave some tar within the hydrocarbon zones. Tar occupies a portion of the pores and may plug partially or fully the pore throats, significantly affecting the fluid flow in the reservoir. Detection of tar is of high significance in the field development for understanding the recovery and effectiveness of water/gas injection. Tar can be easily identified in the water zones using the resistivity response. In the oil zone, it is difficult to separate tar and hydrocarbons by using exclusively a resistivity log. NMR transverse T2 relaxation contains useful petrophysical and geological information. The T2 histogram is a function of both fluid properties and pore size distribution. Tar is almost solid and the hydrogen it contains relaxes very fast because of its strong binding forces. The shortened T2 in the presence of tar results in lower NMR porosity, compared to the conventional Density-Neutron porosity. The missing porosity from NMR along with other conventional logs and wireline formation tester can be reliably used in the evaluation of tar in the formation. The results can be quantified with confidence after calibrating with core results. Two examples are presented from the carbonate formations of Abu Dhabi, in the Middle East, where tar evaluation was successfully performed using NMR, Density- Neutron and MDT data. Introduction Presence of tar in an oil reservoir due to its negative effect on flow performance in porous media may represent a significant problem for field management if not recognized and characterized properly. It is essential to know as early as possible volume and spatial distribution of tar to minimize field development risks, and optimize drain areas while guaranteeing effective pressure maintenance. The giant Middle East field studied in this paper is an anticline structure consisting of three major reservoirs. The reservoirs under investigation, respectively 40 &140 feet thick Lower Cretaceous carbonates, are the top and middle ones. Both reservoirs have been developed using five spot patterns with 1.4 km spacing between the injectors and producers. One of the key uncertainties in the Northern and Eastern part of the field is the area and vertical distribution of bitumen in the reservoirs. Development optimization studies for the Northern and Eastern flank areas recommended several producers and injectors in phases so as to enhance the production from the field. From reservoir development perspective, identification and distribution of bitumen therefore, becomes crucial in order to optimize the horizontal well locations and placement of laterals. In addition, it is very critical to understand the impact of bitumen on the effectiveness of peripheral injectors for reservoir management. The bitumen is associated with the historical oil water contact (OWC) prior to tilting of the reservoir to the present day contacts. It is postulated that on tilting, a section of the reservoir was left with a residual hydrocarbon that degraded to bitumen. The approximate tar area distribution derived from an earlier study is displayed in Fig-1. This will actually be the starting point for a new detailed analysis. The paper discusses the historical approach for tar identification in this field and a quantitative methodology using the new technology NMR logs.
Introduction &Summary Fifteen hundred square kilometers of the 3D OBC Seismic Survey was acquired, over an 18-month period in 2000 and 2001, as a joint Venture between ADNOC, ADMA-OPCO and ZADCO. The seismic acquisition contractor was Petroleum Geo-Services (PGS). This paper concentrates on some of the Operational, Quality &HSE aspects and the many challenges faced in acquiring such a highly specified orthogonal OBC survey (in excess of 300 fold) over a very active field which is extremely densely populated with infrastructure and partly located over very shallow water. The field has hundreds of well head towers (jackets), huge super complexes, satellite platforms and many hundreds of kilometers of criss-crossing, untrenched oil, gas and water pipe-lines. Areas of dense coral pinnacles and other field debris exist. Water depths less than 5m were measured but even these depths were effectively reduced in many areas by the presence of the hazards. Compound the above with super complexes up to several hundred meters long, construction vessels &barges, stimulation vessels, supply vessels, diving vessels, other survey vessels, shuttle vessels, production activities, hundreds of mooring buoys, a field operated by multi ethnic/linguistic workforce and dual Oil Company Operatorship. Throw in a seismic crew consisting up to 9 vessels, 150 crew, 120 kilometres of OBC cables and the ingredients are complete for what must be one of the most complex and intensive OBC seismic surveys ever to be acquired anywhere in the world! The immense Operational, HSE and Quality challenges of the survey were overcome by an incredible level of Joint Venturer team work, excellent communications, extensive risk assessment, operational safety audit, innovation, peer assist and, not least, having a world class seismic acquisition contractor. Basic Acquisition Parameters and Statistics The seismic survey commenced in August 2000 and completed mid-January 2002 at an average daily production rate of just under 3 square kilometers per day. A total of 1505 square kilometres of full fold data was acquired using an orthogonal technique (source lines perpendicular to receiver lines as opposed to parallel in the ‘swath’ technique) to yield a wide azimuth data set fit not only for structural interpretation but also for advanced reservoir characterization purposes. The exceptionally high fold (by comparison to other typical OBC surveys) was obtained through 100m and 300m source and receiver line spacing respectively, 6 active OBC receiver lines, an in-line and cross-line maximum offset of 3600m (yielding a ‘diagonal’ maximum offset of 5100m). For spares and repair inventory purposes up to 120kilometres of cable were available. A working (at sea) spread of 6 receiver lines of 14.4 km each (total 86.4km) was typical although more active cables were utilized during the shallow water portion of the survey due to restricted access for the dynamically positioned recording vessels. The receiver cables were rolled in-line as opposed to cross-line, the latter of which has tended to be more typical of OBC surveys. The receiver station interval was 50m with an, effectively, point array.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents the best practices and the lessons learnt from a comprehensive offshore 3D ocean bottom cable (OBC) seismic survey, which was successfully carried out over a super-giant offshore production oil field in Abu Dhabi by an integrated multi-disciplinary team from three different companies. This work highlights a wide range of challenges and achievements throughout the steps, from the feasibility study, data acquisition, processing, interpretation and advanced reservoir characterization studies.
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