TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractKing Field is located in the Deepwater Gulf of Mexico (GOM) about 110 miles SE of Venice, Louisiana in Mississippi Canyon blocks 84, 85, 128, and 129 (Fig. 1). The main sand, the Upper Miocene 70 (UM 70), is an undersaturated oil reservoir. The sands were deposited by gravity flow processes within an intraslope basin. The formation is highly porous and permeable (31%, 1000md). Lateral and vertical heterogeneities identified by seismic amplitudes and Amplitude Versus Offset attribute analyses have been confirmed by, and calibrated to, well logs, cores and flow tests. Sedimentary facies studies have shown that at least two different styles of deposition are present; lower massive sheet sand, and an upper sand which is more variable and probably channelized. The trap is a three-way antiformal closure against a major fault with a hydrocarbon column of 1400 ft.Permeability and pressure data were obtained from core, nuclear magnetic resonance (NMR) measurement, MDT* Modular Formation Dynamic Tester, closed chamber, flowback and recent permanent gauge data. This paper compares and demonstrates the utilization of results from each source of measurement on different wells. Differences and agreements of these data are discussed. 1 This work demonstrates the use of these data to define a geologic model and better predict well productivity and reservoir continuity. Lessons learned from integrating these multiple sources are summarized.
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C~hl 1S96 Soc@Y of PefrOINNII ErKIIrmers,km Thm paper wu praparad fw presenmfum at b+ 1SS6 SPE Arww.MlTec+mIIA Ccnferefwu * Exhdxtcn hela m Oenvar. Colorado U S A, 6-9 OUckar 1996 Ths paper was sebcmd for ws.antatmn by m SPE Pr~am Cwnmrtlee follmwng rewew of mfcmnatm comamd m MI absmct wbmrtwd by the SUIIW(*) Coc4mnlsof the paper as prmsnled, fmve IWI been rww!lWJ by me Socufy d PWO!eLun Ewn6em and me subIect 10 cartiba by @ author(s) Tf'N mafsrkl, a8 pmaantec, does nof rIOMas&%V Msc4 any posfim of ttu~ty cdPetmM EnOIIWW8,its c4Ecam,or mnmbwa Papars pm$entad al SPE mrntmgs am s@M to wbtitcm rswew by Edrnonal Canmttkes cd the SacmfY of Patrokwn Enpmsus P.nnusmn to copy u rosmcmd to M &slrrn of rot more !fwn 203 wcfds Illuslratans may rwt ba cqxed Tho abstract 8twu!d ccmmm cnnspcu-aus ackKw-ec@Ient of wtwre acd by m lhe pqmr was P+*wniad VMe Lbmnm, SPE, P O BOX Ml&36 RKh=dscm TX 7%Y32-262S U S A, lax 01-214.962-9435 AbstractThis paper discusses the pre-driIl evaluation and post-drill results of a four well horizontal drilling program in two bottom water drive reservoirs with 20 foot oil columns. The pre-drill evaluation consists of a multidiscipline reservoir interpretation that combines 3-D seismic, strati graphy, oil correlation, reservoir model simulation, and performance. Factors critical to the successfid execution of the drilling program were hole size, rig selection and drill-in fluids. Program results are derived from measured while drilling open hole logs, well performance, flowing pressure data, and production logging, The paper analyzes the complexities of production log interpretation in two phase horizontal flow.
Measurement-while-drilling (MWD) information accurately defined gas, oil, and water in an offshore field. Basic MWD and wireline formation evaluation data compare favorably. A cost saving of $130,000 was realized when MWD information was used instead of wireline data on one well. In the future, MWD logs may serve as the primary evaluation data on routine development wells in similar fields.
The Who Dat field is located in Mississippi Canyon 503 under 3,100 ft of water, penetrating 11 stacked horizons between 10,000 – 18,000 ft, in Pliocene and Upper Miocene age. The Who Dat OPTI-EX® semi-submersible FPS was the first FPS built on speculation, and was the first privately owned FPS in the world. The field was discovered in December 2007, initial production in December 2011, and the field paid out in 2014. The field has produced more than 52 MMSTB of oil and 99 BCF of gas as of year-end 2017. This paper will cover the integrated reservoir study of the Who Dat field, which includes geological modeling, data management, reservoir surveillance, construction of the integrated reservoir models, history match and forecast of the integrated models, depletion plan optimization, production operation optimization, sensitivity, and uncertainty analysis. The eleven different horizons in the Who Dat field have various depositional environments, petrophysical properties, and fluid properties. As a result, the optimum depletion plan needs to be uniquely designed for each reservoir, as well as for the field as a whole. The biggest reservoir, the 4600, exhibited steep pressure decline and great connectivity which made it a potential candidate for water flooding. However, the facilities do not have space or weight capacity for the water flood equipment, which leaves only high cost solutions such as major platform modifications (wing decks, hull blisters) or building a standalone facility on the Shelf. Based on a thermal simulation model, the injected cold water viscosity is several times higher than the in-situ water which decreases the injectivity of the water injectors. Even though the water flood project was expected to increase ultimate oil recovery significantly, the project team recommended not going forward with the project based on the integrated reservoir study and the resulting economics. If the water flood project was sanctioned, the field would not pay out for years and the net present value of the project would be significantly decreased. The second biggest reservoir, the 4700, had a downhole sample showing undersaturated oil with a GOR of 1,280 SCF/STB; however, the well experienced an abnormally high 4,500 GOR when put on production. A later well that penetrated the updip area showed the zone to be gas bearing, which indicated the reservoir is not in equilibrium with a gas cap and undersaturated oil rim. The project team decided to decrease the rate to see whether the well was rate sensitive. With the help of multiphase meters, the team observed that with decreased rate, the GOR dropped to less than 2,500, and the productivity index increased from 4 stb/psi to 14 stb/psi. By continuing to produce the well at a reduced rate the ultimate recovery significantly increased. The reservoir models have been very consistent after a couple of years’ production. The production and pressure forecast from the 2014 history matched models are within 10% of the historical data, which provides confidence in the integrated model. After 6 years of production, the project team is still actively updating and utilizing the integrated models to evaluate future development wells, secondary recovery opportunities, and production optimization to further increase the value of the Who Dat field.
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