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Collaborating Authors
Investigation of Salt-Bearing Sediments Through Digital Rock Technology Together With Experimental Core Analysis
Rydzy, Marisa B. (Shell International Exploration and Production) | Anger, Ben (Shell International Exploration and Production) | Hertel, Stefan (Shell International Exploration and Production) | Dietderich, Jesse (Shell International Exploration and Production) | Patino, Jorge (Shell International Exploration and Production) | Appel, Matthias (Shell International Exploration and Production)
Abstract In this study, digital rock analysis was combined with a variety of experimental core-analysis measurements to investigate the effect of salt saturation and distribution on the porosity and permeability of halite-cemented core samples. Medical and micro-X-ray CT scans of core sections and 2.54-cm (1-in.) diameter plugs indicated that the halite generally occurred in the form of distinct layers. High-resolution micro-X-ray computed tomography (MXCT) images acquired of 0.6-cm diameter plugs revealed that, on the pore scale, halite appeared to be pore filling. Pores were either completely filled with halite or did not contain any halite at all. It was also observed that halite preferentially occurred in the larger pores associated with larger grain sizes. The porosity and permeability results, both measured experimentally on the core plugs and calculated by segmentation of the MXCT images, demonstrated the obstructive effect of halite on storage and flow as well as the decline of both properties with increasing salt saturation. Comparison of calculated and measured values showed that the measured porosity could be up to 6 porosity units (p.u.) higher than the calculated one, while the measured permeability of core plugs after salt removal was an order of magnitude lower than the one obtained by lattice Boltzmann simulation. One possible reason for this discrepancy may be the stratified nature of the samples. While the fully salt-saturated plugs appeared homogeneous in MXCT images, post-flood MRI images revealed that the plug was composed of layers with different MRI intensities, i.e., different amounts of water-filled porosity. Consequently, the petrophysical parameters calculated for the miniplugs may only be representative for a section of the core plug. The results of the MRI-assisted corefloods emphasized the importance of considering different scales when interpreting and applying the results of digital rocks analysis.
- Europe (1.00)
- North America > United States > Mississippi (0.47)
- North America > United States > Texas > Harris County > Houston (0.28)
- North America > United States > Mississippi > Pelahatchie Field (0.99)
- North America > United States > Mississippi > Mississippi Salt Basin (0.99)
- North America > United States > Gulf of Mexico > Norphlet Formation (0.99)
- (4 more...)
Halite Pore Space Plugging Evaluation Based on the Logging Data for the Cambrian Ara Group Intra-Salt Tight Carbonate Reservoirs (South Oman Salt Basin)
Smirnov, Dmitrii (Petroleum Development Oman) | Hashmi, Mohammed (Petroleum Development Oman) | Al Hadhrami, Abdullah (Petroleum Development Oman) | AL Isaee, Omar (Petroleum Development Oman) | Fanis, Khayrutdinov (Petroleum Development Oman) | Agrawal, Pankaj (Petroleum Development Oman) | Kumar, Kamlesh (Petroleum Development Oman) | Kaabi, Saqer (Petroleum Development Oman)
Abstract There has been a string of exploration discoveries in Cambrian Ara Group intra-salt carbonate reservoirs in the South Oman. Some of the reservoirs failed to produce at expected rates due to halite presence in the pore space, which is one of the highest risks for hydrocarbon exploration in this area. The objective of this study was to define novel quantitative algorithm to estimate halite volumes in the pore space. Although halite cementation is known as a major risk for hydrocarbon production, a limited number of studies have focused on the impact of halite cementation on productivity, well integrity and ultimate recovery. The quantitative halite volume evaluation based on the logging data required an integrated approach to open hole and cased hole data collection and analysis. The open hole data included: thin section and XRD core analysis, density, neutron, sonic, resistivity, formation pressure and sigma capture-cross section. Net pay cut-off based on calculated halite volume was defined. Cased hole production logging was used to confirm net cut-off definition. The integrated logging data analysis and the developed quantitative halite volume evaluation algorithm mainly based on sigma log was successfully implemented in a few ongoing development projects. The evaluation results were successfully used for hydrocarbon volume calculations, well placement and perforation interval selection to improve production performance and reduce field development uncertainty in recoverable volumes. Understanding of consistent pattern for halite distribution allow improve exploration success. Avoiding perforation of intervals with high halite content in the pore space reduced production deferment due to surface equipment and tubing plugging by salt. Appreciation for the role of halite plugging in the reservoirs properties distribution and deterioration significantly improve history match for hydrodynamic models. The evaluation algorithm for quantitative halite volume estimation in the pore space have been developed and introduced for the first time and benefits from its implementation are expected for the upcoming exploration and development projects for the salt encased carbonate reservoirs.
- Geology > Mineral > Halide > Halite (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.30)
Assessment of Halite-Cemented Reservoir Zones
Huurdeman, A.J.M. (TNO Inst. of Applied Geoscience) | Breunese, J.N. (The Geological Survey of The Netherlands) | Al-Asbahi, A.M.S. (Ministry of Oil and Mineral Resources, Republic of Yemen) | Lutgert, J.E. (TNO Inst. of Applied Geoscience) | Floris, F.J.T. (TNO Inst. of Applied Geoscience)
Summary This paper describes the techniques used to identify the presence anddistribution of presence and distribution of halite-cemented layers in asandstone reservoir. The distribution of these layers in the wells was found bymatching the core data with two independent halite identifiers from the welllogs. Numerical well models were used to assess the dimensions and spatialdistribution of the halitecemented layers. Multiple simulation runs in whichthe spatial distribution, the dimensions, and the vertical permeability werevaried resulted in a permeability were varied resulted in a stochastic modelthat best matched the production history. Gas and water coning are retarded bythe halite-cemented layers if the perforations are properly located.perforations are properly located. Introduction The Azal field is located in the Marib AlJawf basin in the Republic of Yemen(Fig. 1). Of the 20 wells spudded in the field, 13 are oil-production wells andone is a gas-injection well. Production started in May 1988. The reserves areestimated to be 142 × 10(6) bbl [22.6 × 10(6) m3] of oil and 568 × 10(9) scf[16.1 × 10(9) std m3] of gas. The Azal field is an extension northeast of thelarger Alif field, from which it is separated by a half-graben structure. Thefield is 5.6 miles [9 km] long and 0.9 mile [1.5 km] wide. The depth of the topof the reservoir is 6,625 ft [2019 m], which is 3,425 ft [1044 m] below meansea level (MSL). The oil column, with a 39 degrees API [0.830g/cm3]-specific-gravity oil, has an average thickness of 80 ft [24.4 m]. The maximumga-column thickness is 240 ft [73.2 m]. The gas has a high liquid content, andthe underlying aquifer is oversaturated with salt. The Alif field, which hascharacteristics similar to those of the Azal field but a thicker oil column, started production in March 1986. After some time, salt deposition clogged anumber of wells and production facilities. Special measures were necessary toprevent production loss. The salt deposition may have resulted from pressureand temperature changes in the brine produced concurrently with the oil as aresult of water coning. No halite was observed during the formation evaluation;however, no special attention was paid to this aspect at that time. Indicationsof balite were found in the Azal field formation. A detailed core analysisrevealed the existence of diagenetic, postcompactional halite in the Alifmember postcompactional halite in the Alif member (the main hydrocarbon-bearingunit). Furthermore, the production history of the Azal field showed gas andwater production rates lower than those anticipated from the coningcalculations, which indicated that the flow path to the well was prolonged byflow path to the well was prolonged by flow barriers. In this very cleansandstone reservoir with a minor amount of diagenetic minerals, flow barrierscould well be made up of halite-cemented layers. The central issue addressed inthis paper is whether the balitelcemented layers observed in the reservoir willinfluence salt deposition in the wells and production facilities of the Azalfield by retarding water and thus salt flow through the oil column to thewells. This information is important for the planning of well locations andperforation intervals. To investigate this issue, perforation intervals. Toinvestigate this issue, a method was developed to determine the existence ofhalite-cemented zones in wells for which only well logs are available. Thedistribution and dimensions of these zones were studied from a gelogicalviewpoint by looking at the deposition history and from an engineeringviewpoint by examining the production history with numerical well productionhistory with numerical well models. Numerical models also were used to studythe influence of the halite-cemented zones on salt deposition in the wells andon reservoir management. Field Description The Azal field is situated in the Marib AlJawf basin, which trends northwestacross the southwestern corner of the Arabian Peninsula. The basin ischaracterized by a Peninsula. The basin is characterized by a half-grabenstructure divided into several sub-basins, one of which contains the Azalfield. The dominant fault trends are parallel to the basin axis(northwest/southeast). The Azal field is bounded on the southwest by asouth-dipping fault and on the north and east by a dip enclosure. Thestratigraphic time setting of the Mesozoic formations is still subject todiscussion. The term "Alif formation," the main hydrocarbon-bearingformation, refers here to marine, deltaic, and fluviatile sequences below themain evaporite sequence (Main Salt) and above the turbidites (Upper Amran or Lam formation). Palynologic evidence indicates that the deposition of theentire Alif formation occurred during the Tithonian stage. Five geologicalunits can be recognized in the field (Fig. 2). The marine shales of the local Sean member contain turbidite sandstones. A delta shoreline facies forms thetransition zone between the marine shales and the overlying sandstones of the Alif member. The fluviatile and deltaic facies of the Alif member consist ofclean sandstones. The overlying transgressive shale member consists ofsandstones and shales and reflects the beginning of a major transgression. P. 518
- Europe (1.00)
- Asia > Middle East > Yemen > Ma'rib Governorate (0.45)
- Asia > Middle East > Yemen > Amran Governorate > Amran (0.24)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Halide > Halite (1.00)
- Asia > Middle East > Yemen > Ma'rib Governorate > Sab'atayn Basin > Alif Field > Alif Formation (0.99)
- Asia > Turkmenistan > Caspian Sea > Cheleken Contract Area > Block 2 > Lam Field > Zone 7 Formation (0.98)
- Asia > Turkmenistan > Caspian Sea > Cheleken Contract Area > Block 2 > Lam Field > Zone 6 Formation (0.98)
- (3 more...)
ABSTRACT Sedimentary facies and their diagenetic equivalents in Zechstein carbonates and adjacent evaporates are determined from wireline logs using a petrophysical database calibrated in14 key wells. The selected key wells have between 8and100% core cover with49% on average, and a logging suite consisting of density, neutron, photo-electric factor (Pe), sonic, gamma ray, deep, shallow and micro-resistivity logs. The database was constructed in three major steps:A volumetric analysis incluing mineralogical composition, porosity and saturation was computed usin an iterative minimisation program and checked against petrophysical core data, petrographic data provided by core description, and mineraolgical data based on microscopy and X-ray analyses. Principal minerals were calcite, dolomite, anhydrite, and halite with occasionally significant amounts of potassium salts, pyrite, clay, sulfur, and bitumen. Gas corrections based on the calculated saturations were used to normalized the logs for each key well. The gas-corrected log data were then grouped using a cluster analysis of their principal components to obtain electrofacies for each single well. These electrofacies were matched with geological facies defined from the petrographic core descriptions. Log data values of similar electrofacies from the individual key wells were plotted in 10 two-dimensional multiwell-crossplots. To avoid ambiguities produced by the cluster analyses an independent five-dimensional ellipsoid was created from the multiwell-crossplots for each geological facies. The defined ellipsoids were combined to forma petrophysical database. In general the following carbonate facies with significant differences in log responses are distinguished based on different mineralogies and porosity types:" replacement dolomites such as mudstones, mouldic mudstones, wacke-, grain- and packstones, which show a curved density/neutron response," recrystallized dolomites derived from successive microsolution, accretive crystallization and subsequent compaction, which show a straight line response in the density/neutron crossplot;" replacement and recrystallized dolomites as above, but evaporite cemented with anhydrite and/or halite;" dedolomites including layered, nodular (concretionary), vuggy types and calcite-cemented grainstones;" limestones divided into micrites, sparitic mudstones, wacke- and grainstones. Petrophysically significant traces of minerals such as pyrite and evaporite mixes also require separate ellipsoids, resulting in 48 carbonate and 24 evaporite lithofacies. The correctness of the database was verified on three cored test wells. Evaluation using old logging suites consisting of density, sidewall or gamma-ray neutron, gamma ray, sonic and laterolog seven is now also performed. Routine application of the database provides complete facies descriptions in uncored sections and wells for use in geological profiles and facies maps.
- Europe > Germany (0.50)
- Europe > Netherlands (0.46)
- North America > United States > Texas (0.28)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.98)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.80)
- North America > United States > Texas > Sligo Field > Sligo Formation (0.99)
- North America > United States > Louisiana > Sligo Field > Sligo Formation (0.99)
- North America > United States > Arkansas > Sligo Field > Sligo Formation (0.99)
- (7 more...)
Summary. The fields in the Esmond complex (Esmond, Forbes and Gordon)produce gas from the Triassic Bunter sandstone formation. Production producegas from the Triassic Bunter sandstone formation. Production started from allthree fields in 1985, and an annual cased-hole, pulsed-neutron-monitoringprogram was initiated in 1986. The main pulsed-neutron-monitoring program wasinitiated in 1986. The main objective of this program was to detect changes information water saturation resulting from invasion by influx from the aquifer. Initial interpretation of the pulsed-neutron logs was hampered by two factorsthat make the Esmond complex a borderline environment for this type of logging:a large, gas-idled borehole that attenuates the tool and a halite cement in theformation with a very high capture cross section. Increased understanding ofthese factors has improved the reliability of interpretations. Recent resultsindicate water advance in all three fields. Currently, water production hasbeen observed only on Forbes, the smallest of the three fields. Observedpressure behavior, however, does show the effects of water influx in all threefields, confirming the log indications. Detailed analysis of the log resultsled to the identification of different modes of water influx, either as anoverall rise in the gas/water contact or as fingering along permeable layers. This information is valuable in production planning. Introduction The Esmond, Forbes, and Gordon gas fields of the Esmond complex are locatedin Blocks 8, 13, 15, and 20 of Quadrant 43 in the U.K. southern North Sea(Figs. 1 and 2). Gordon field was discovered in 1969, Forbes in 1970, and Esmond, the largest, in 1982. Current estimates of initial gas in place are Esmond at 400 Bcf [11 × 10(9) m3], Gordon at 180 Bcf [5.1 × 10(9) m3], and Forbes at 100 Bcf [2.8 × 10(9) m3]. The three fields went on production in1995. Esmond produces through seven wells drilled from a wellhead tower linkedto an adjacent central processing platform. Satellite platforms in Forbes and Gordon, with three producing wells each, are also lined to the Esmond centralprocessing facility (Fig. 3). Gas is exported by pipeline to Bacton on the Norfolk coast. The wells are completed with 9 5/8 -in [24.4-cm] casing over thereservoir interval. The 7-in [17.8-cm] tubing completion gives a minimum3.99-in [10.1-cm] ID if the subsurface safety valve is removed. This permitsthe running of full 3 5/8-in [9.2-cm] -diameter logging tools. By Dec. 31,1988, cumulative production totaled about 240 Bcf [6.8 × 10(9) m3]. Geological Setting. Each field in the Esmond complex is a simple, unfaulted, domal structure, resulting from diapirism in the underlying Permian Zechsteinevaporates. Gas is produced from the Triassic Middle Bunter sandstone. From apetrophysical standpoint, the most significant feature of the Bunter sandstonein this area is the high but varying proportions of halite cement, which isoften pore occluding. proportions of halite cement, which is often poreoccluding. Clays are present, predominantly in illite and kaolinite forms, butbecause of the salt-saturated pore water, have little effect on petrophysicalproperties. The Middle Bunter interval is subdivided into seven reservoirsubzones, as shown in Fig 4, Zone 2, which is predominantly shale, is presentin all wells and forms an effective pressure barrier between Zone 1 andunderlying Zones 3 through 7. Openhole Log Interpretation. Successful interpretation of open-hole logs inthe gas-bearing Bunter sandstone relies on the ability to distinguish salt fromgas. The traditional density/neutron gas-sand interpretation technique islimited by the fact that both gas and salt produce a positive density/neutronlog separation, as illustrated by the density/neutron crossplot over a typicalinterval in Esmond Well 43/13a-C7 (Fig. 5). Additional use of the sonic logresponse helps to distinguish gas from halite, as illustrated by the log curvesfrom the above interval in Fig. 6. With an appropriate choice of scaling, thesonic log clearly tracks the density in sandstone intervals and shows adeparture toward the neutron curve in salt-cemented layers. The above findingwas incorporated into the interpretation technique, which involved the solutionof a series of simultaneous equations representing responses of the density, neutron, sonic, and gamma ray log curves to the shale, halite, sand, gas, andwater components with the addition of anhydrite in the overlying Rot haliteformation. This calculation was made with the matrix solution technique in the PETRA (TM) module of T-LOG (TM), a commercial log-analysis package. Fig. 6 alsoshows the results of this computation for Esmond Well 43/13a-C7. Withsalt-saturated formation brine, electrochemical shale effects are assumed to benegligible and water saturations are calculated with the standard Archieequation. Average porosities in the gas-bearing sands range from 15 to 22% inall three fields. Average calculated water saturations for Esmond and Forbesrange from 15 to 25%. In Gordon, log-derived water saturations are higher (from25 to 35%), probably a function of the lower permeabilities seen in thesesands. permeabilities seen in these sands. Core-analysis data are of limitedreliability in the Bunter sandstone because of the presence of halite cement. Salt-dissolving cleaning fluids destroy the rock fabric. If these fluids arenot used, however, salt precipitated from the formation brine may furtherocclude pore spaces, making any comparison of log- and core-derived porositiesproblematic and increasing the uncertainty of electrical and capillaryproblematic and increasing the uncertainty of electrical and capillarymeasurements. Problems of Pulsed-Neutron Response Problems of Pulsed-Neutron Response Borehole Effects. Fig. 7 is an example of the measured capture cross sectionfrom one of the first Atlas PDK-100(TM) pulsed-neutron decay logs run in Esmondin 1985. Fig. 7 also shows the well configuration and openhole lithologicalinterpretation. At the time of logging, the response of the PDK-100 tool wasthought to be independent of borehole effects; however, as is evident in Fig.7, the measured capture-cross- section curve shows distinct changes at thetubing shoe and the borehole gas/water interface. Also disturbing was the factthat the measured capture cross section opposite the Rot halite formation wasmuch lower than the expected value for pure halite. The tool did appear torespond to the halite-cemented layers in the lower section of the hole, however, where the casing was standing full of completion brine. The apparentlyanomalous response of the PDK-100 in Esmond led us to doubt the viability ofpulsed-neutron tools for long-term monitoring in these fields. In an attempt toinvestigate these problems further, two different pulsed-neutron tools, Schlumberger's thermal-decay-time (TDT-M(SM)) tool pulsed-neutron tools, Schlumberger's thermal-decay-time (TDT-M(SM)) tool and capture-mode inducedgamma ray spectrometry tool (GST(SM)), were run in Esmond Well 43/13a-C7 in1986. The capture-cross-section curves (Fig. 8) show effects similar to thoseseen on the PDK-100 in 1985, confirming at least the repeatability of thepulsed-neutron measurement. Note that, in the gas-filled borehole section, thecapture cross section measured by the GST is significantly higher than that ofthe TDT, while both curves agree quite well over the water-filled section. SPEFE P. 327
- North America > United States (1.00)
- Europe > United Kingdom > North Sea > Southern North Sea (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Halide > Halite (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.65)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 43/13 > Esmond Field > Middle Bunter Sandstone Formation (0.96)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 43/20a > Gordon Field > Bunter Formation (0.95)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 43/15a > Gordon Field > Bunter Formation (0.95)
- (2 more...)