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Richardson, Texas and Tulsa, Oklahoma (25 May 2021) -- The American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers (SPE) announce an exploration of the benefits and opportunities of a merger creating the energy professionals' organization for the future. With unanimous consent from the AAPG Executive Committee and the SPE Board of Directors, a steering committee was created to explore opportunities to form a new combined organization in response to an evolving energy sector and challenging COVID-impacted market environment. "Our two organizations have worked together side by side for many years on numerous initiatives and global events, notably the Offshore Technology Conference, International Petroleum Technology Conference, Unconventional Resources Technology Conference, and the Petroleum Resources Management System. Joining forces would bring the best of both organizations together and provide additional value to engineers, geoscientists, and the broader energy sector," said Rick Fritz, AAPG President. The industry relies on subsurface geoscience and engineering teams rather than siloed disciplines.
Robert A. Wattenbarger, SPE, died on 9 May 2014. He was 78. An active SPE member for 53 years, he was the recipient of the SPE Reservoir Description and Dynamics Award in 2012 and was inducted into the SPE Legion of Honor in 2000. Wattenbarger started his career in 1959, working with Mobil Oil in Colombia. He went on to work for Oil Recovery Corporation and Sinclair Oil in Tulsa, Oklahoma, then Mobil Research in Dallas, Texas, where he developed the first practical compositional reservoir simulator. In 1969, Wattenbarger joined Scientific Software Corporation as vice president, where he remained for 10 years. In 1979, he started his own consulting firm in Houston, joining Texas A&M University as a faculty member in 1983. He had recently been appointed holder of the John E. and Deborah F. Bethancourt Professorship at Texas A&M. Wattenbarger received a BS in petroleum engineering from the University of Tulsa and a PhD in petroleum engineering from Stanford University.
Paper SPE 99240 presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, USA, 22-26 April. Paper SPE 164648 presented at the North Africa Technical Conference and Exhibition, Cairo, Egypt, 15-17 April. Paper SPE 89704 presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 26-19 September. Paper SPE 39749 presented at the SPE Asia Pacific Conference on Integrated Modelling for Asset Management, Kuala Lumpur, Malaysia, 23-24 March. Paper SPE 140337 presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, The Netherlands, 1-3 March.
Bourbiaux, Bernard (IFP Energies nouvelles) | Fourno, André (IFP Energies nouvelles) | Nguyen, Quang-Long (IFP Energies nouvelles) | Norrant, Françoise (IFP Energies nouvelles) | Robin, Michel (IFP Energies nouvelles) | Rosenberg, Elisabeth (IFP Energies nouvelles) | Argillier, Jean-François (IFP Energies nouvelles)
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 12-16 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Among various ways to extend the lifetime of mature fields, chemical EOR processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR as the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. However, a wide variety of surfactants can now be considered for EOR, among which products that alter the matrix wettability. The present paper deals with that recovery strategy and compares it with other strategies based on viscous drive enhancement. Comparison is based on the physical and numerical interpretation of original representative experiments. The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs has been quantified thanks to X-ray CT-scanning and NMR measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves could be inferred from in-situ fluid saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, representative drive conditions of a fractured reservoir were imposed between the end-faces of a plug, in order to account for the possibly-significant contribution of fracture viscous drive to matrix oil recovery. These experiments were carefully analyzed and their numerical modeling was initiated with a simulation software that takes into account the multiple effects of surfactant presence on rock-fluids systems, including rock wettability modification and water-oil interfacial tension reduction.
Suijkerbuijk, B. M. (Shell Global Solutions International) | Hofman, J. P. (Shell Global Solutions International) | Ligthelm, D. J. (Shell Global Solutions International) | Romanuka, J.. (Shell Global Solutions International) | Brussee, N.. (Shell Global Solutions International) | van derLinde, H. A. (Shell Global Solutions International) | Marcelis, A. H. (Shell Global Solutions International)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Eighteenth SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 14-18 April 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Improved oil recovery by low salinity waterflooding (LSF) represents an attractive emerging oil recovery technology, as it is relatively easy to implement and low-cost compared to other Improved and Enhanced Oil Recovery (IOR and EOR, respectively) processes. Even though LSF leads to extra oil recovery in most laboratory experiments and some promising data from the field have been presented, the mechanism underlying LSF is still unclear. Therefore it is difficult to predict a favorable performance of LSF in one field a priori, while dismissing others. This paper describes a series of spontaneous imbibition experiments on Berea outcrop core plugs, and some reservoir rock core plugs, that were designed to determine the impact of formation water, imbibing water and crude oil composition on wettability and on wettability modification by LSF. The data presented in this paper lead us to conclude that: - Spontaneous imbibition experiments with formation brine and low salinity brine executed on Berea outcrop material aged with a crude oil show excellent reproducibility; - An increasing concentration of divalent cations in the formation brine makes a Crude Oil/Brine/Rock system more oil-wet; - The extent of wettability modification towards more oil-wet upon aging also depends on the types of cations in the formation brine; - Improved oil recovery by exposure of the aged plugs to NaCl brines occurred when the imbibing phase was either higher or lower in salinity than the formation brine; - Aging of the same brine/rock system with different crudes having diverse physico-chemical properties led to: o A spread in wettabilities after aging o A crude oil-dependent low salinity effect These results are discussed within the context of several mechanisms that have been put forward previously as an explanation for the low salinity effect.
Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the 2010 SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 24-28 April 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Condensate blockage is known as a serious problem in gas condensate reservoirs due to the depletion of reservoirs to pressures below the dew point. It reduces gas phase relative permeability and consequently results in the loss of gas productivity. The objective of this study was to identify and attempt to remedy this blockage problem through reservoir wettability determination and wettability alteration by using surfactants in the condensate buildup regions. Experiments were performed at ambient conditions by using stock tank condensate sample, methane, synthetic reservoir brine, and quartz substrate. In this study, both the spreading coefficient and wettability were measured to characterize the influence of anionic and nonionic surfactant on interfacial behavior. The contact angles were experimentally measured using Dual-Drop-Dual-Crystal (DDDC) technique. The Drop Shape Analysis (DSA) and capillary rise technique were used for measuring oil-water, watergas and gas-oil interfacial tensions. An advancing angle of 152 obtained from the experiments indicated that this sandstone condensate reservoir had a strong oil-wet nature. Anionic and nonionic surfactants at the concentration levels of 500, 1500, and 3000 ppm were tested in the experiments. Results showed that although spreading coefficients were all positive for the condensate-brine system with/without surfactants, they decreased after the surfactants application. This implies that oil recovery is still enhanced from surfactants usage in this strongly oil-wet system. Also, all three concentrations of anionic surfactant were shown to alter the wettability of quartz surface from strongly oil-wet to intermediate-wet or weakly oil-wet. However, no wettability alteration was found after nonionic surfactant usage. The key finding from the ambient condition experiments is that the sandstone reservoir wettability is altered from strongly oil-wet to intermediate-wet or weakly oil-wet by using an anionic surfactant.
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 75250, "Evaluation of Crossflow Effects in Multilateral Wells," by D. Zhu, SPE, and A.D. Hill, SPE, U. of Texas at Austin, and W.R. Landrum, SPE, Conoco Inc., originally presented at the 2002 SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 13-17 April.
This article is a synopsis of paper SPE 39637, "A Small, Independent Producer's Design, Construction, and Operation of a Flue-Gas-Injection Project, East Edna Field, Okmulgee County, Oklahoma," by John Godwin, Driver Production; Trevor Lyons, Lyons & Lyons Inc.; Nancy Richardson, SPE, Oklahoma Independent Petroleum Assn.; and David Olsen, SPE, Unitar Centre for Heavy Crude and Tar Sands, originally presented at the 1998 SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 19-22 April.
Wherever sizeable washouts exist behind cemented pipe the gamma curve will be Downhole Sigma measurements have been with us for more greatly reduced as compared to an open hole gamma curve.
Bragg, J.R. (Exxon Production Research Co.) | Gale, W.W. (Exxon Production Research Co.) | McElhannon, W.A. (Exxon Production Research Co.) | Davenport, O.W. (Exxon Co. U.S.A.) | Petrichuk, M.D. (Exxon Co. U.S.A.) | Ashcraft, T.L. (Exxon Production Research Co.)
The paper was presented at the SPE/DOE Third Joint Symposium on Enhanced Oil Recovery of the Society of Petroleum Engineers held in Tulsa, OK, April 4-7, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words Write: 6200 N. Central Expwy., Dallas, TX 75206.
A successful surfactant (microemulsion) flood pilot test has been completed by Exxon in a pilot test has been completed by Exxon in a watered-out portion of the Weiler sand, Loudon Field, Fayette County, Illinois. The microemulsion system tested was designed to be effective in the presence of high-salinity formation water containing 104,000 ppm (mg/l) total dissolved solids (TDS) without use of a pre-flush. The test was conducted in a single, 0.68-acre pre-flush. The test was conducted in a single, 0.68-acre 5-spot operated to approximate a confined pattern. Approximately 60 percent of the waterflood residual oil present in the pilot pattern was recovered. Extensive data for determining sweep and displacement efficiencies were obtained from observation well logs and fluid tracers. Although problems were encountered with bacterial degradation of biopolymer and with produced oil-water emulsions, the test is considered to be a technical success and confirms the effectiveness of the high-salinity microemulsion formulation. Additional pilot tests are needed to determine the effects on oil recovery of microemulsion bank size and well spacing.
The Loudon Field, operated by Exxon Company, USA in Fayette County, Illinois, represents a challenging tertiary recovery target. It is in an advanced stage of depletion after about 13 years of primary production and 30 years of waterflooding. After production and 30 years of waterflooding. After waterflooding is completed, almost half of the OOIP will likely remain unrecovered. The Loudon reservoirs are Mississippian Chester sandstones ranging in depth from 1400 to 1600 feet subsurface. The depositional environment in the pilot area is generally deltaic with stream-mouth bars and delta fronts containing fine-to-medium grain, well-cemented sands having good well-to-well continuity. Reservoir temperature is 78 deg. F, oil viscosity is 5 cp, and the formation water contains about 104,000 ppm (mg/l) total dissolved solids (TDS) including over 4000 ppm of divalent ions (see Table 1).
An earlier surfactant flood pilot conducted at Loudon in 1969 used a large-volume; low salinity preflush prior to injection of a petroleum sulfonate preflush prior to injection of a petroleum sulfonate surfactant system that was only effective at low salinity. The main conclusion reached from that test, which recovered only about 15% of the residual oil in the test area, was that preflushes are likely to be ineffective unless the surfactant system has a broad salinity tolerance. Much of the surfactant flooding research conducted subsequently by Exxon Production Research Company has been directed toward Production Research Company has been directed toward developing microemulsion systems that are effective in high-salinity reservoirs without requiring a preflush. The test reported here used this type of preflush. The test reported here used this type of microemulsion formulation.
As shown in Fig. 1, the test was conducted in the southern end of the Loudon Field on the 80-acre L. Ripley lease. A single, normal 5-spot pattern of 0.68-acre area was operated to simulate a confined 5-spot. Bottomhole well locations within the test sand at a depth of 1550 feet are shown in Fig. 2. Five fiberglass-cased logging observation wells were included within the pattern to allow use of both induction and carbon/oxygen logs to monitor changes in oil saturation and salinity during the flood. Extensive use was made of observation well logs, fluid tracers, and injection flow surveys to determine both vertical and areal sweep. An objective was to obtain data on bank velocities and displacement efficiencies in various strata and pattern quadrants that would aid in correlating pilot performance with laboratory core floods. Although a small pattern was chosen primarily to permit a rapid process evaluation, the resulting close well spacings also allowed an extremely detailed reservoir description which will facilitate test interpretation.
Pilot wells were drilled and completed in 1977, surface facilities were installed in 1979, and microemulsion injection was initiated on May 13, 1980. The flood was ended on October 16, 1981 after 2.25 PV total fluid production; however, post-flood PV total fluid production; however, post-flood evaluation tests are still in progress. Detailed test interpretation, including modeling of the pilot with a chemical flood simulator, is currently being conducted.