Day 2 Tue, August 06, 2019最新文献

{"title":"Petrophysical Evaluation of the Reservoir in the K - Field, Offshore Ghana","authors":"Prosper Anumah, S. Mohammed, Justice Sarkodie-kyeremeh, W. N. Aggrey, Anthony Morgan","doi":"10.2118/198796-MS","DOIUrl":"https://doi.org/10.2118/198796-MS","url":null,"abstract":"\u0000 Reliable assessment of the petrophysical properties of hydrocarbon-bearing reservoirs is essential for the estimation of hydrocarbon reserves, identification of good production zones, and assessing the need for hydro-fracturing jobs. The K-Field although discovered in the 1970s is yet to be developed.\u0000 In this study, well logs from the wells drilled in this field were analysed with the primary objective of determining the petrophysical properties of the reservoir zones using various estimation models. From the log readings, the reservoir sands containing hydrocarbons in the field are found to be located at the Mid Turonian (90Ma)-Intra Upper Albian (96.5Ma) and Intra Upper Albian (98Ma). The porosity was determined using the density log and crossplots. Archie and Simandoux correlations were utilized in the determination of the water saturation. Permeability was estimated using Timur, Tixer and Coates correlations.\u0000 The findings after the petrophysical evaluation indicate that the wells entered formations with good reservoir quality in terms of porosity, which ranges from 16.12% to 20.97%. In relation to hydrocarbon saturation and permeability, two of the wells gave better results suggesting that they were drilled through the productive part of the reservoir. Nonetheless, the average permeability of the reservoir is estimated to be very low. This suggests that in the field development planning, well stimulation methods should be incorporated to aid the ability of the reservoir rocks to transmit fluids into the production wells.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88988867","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Gas Lift Optimization within Field Capacity Limitations","authors":"Uche Chukwunonso Ifeanyi, Samuel Esieboma, Jennifer Uche","doi":"10.2118/198744-MS","DOIUrl":"https://doi.org/10.2118/198744-MS","url":null,"abstract":"\u0000 Optimizing oil production with facility constraints has become a challenge to most E&P companies even as they pursue sustainable resources. The innovative gas lift technique overcomes this challenge. The conventional gas lift well system has long been in use, but the design most times is limited by gas availability and pressure which limits the depth of gas lift injection for improved production rates. This challenge may not be evident in matured producing fields with gas compressors installed with available non-associated gas source wells, but truly such challenges arise in new fields especially owned by indigenous companies where much uncertainties at an early field life unavoidably allows you to be more stringent in expenditures towards development of a field gas lift project. A new gas lift concept was developed and studied in Field A in an offshore field of the Niger delta in the absence of gas compressors. This design has been proven to be suitable because it was used to bring four closed wells online even when those wells were removed from the company annual forecast. The original design consists of a minimum of two unloading valves and an orifice at a deeper depth, but because of the absence of scrubbers and gas compressors in the facility, pressure depletion in the reservoirs caused four flowing wells to be closed. The new design then sets dummy at shallow mandrels and uses a modified size of orifice to optimize available pressure and gas required to open the closed wells and still sustain other gas lifted wells connected to the same gas lift manifold. This campaign resulted to an additional 7000Bopd which is the primary discussion of this paper.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79339800","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental Investigation of the Effects of Different Environmental Conditions on Pipelines Corrosion Rates","authors":"O. Adeyanju, L. Oyekunle","doi":"10.2118/198708-MS","DOIUrl":"https://doi.org/10.2118/198708-MS","url":null,"abstract":"\u0000 An estimate of about $18.5 million are expended by industries in Nigeria yearly on corrosion, the oil and gas industry takes more than 65% of this cost due to the peculiar nature of their facilities and operational conditions. In spite of the use of galvanized pipeline and application of the anti-corrosion coating of crude oil pipeline and other metallic structure in the oil and gas industry, corrosion failures are still daily occurrences. These corrosive failures have been attributed to the environmental conditions in which the pipeline and other metallic structures are located. This research studies the rate of deterioration (corrosion rate) of carbon steel pipeline (flow pipe) under five different environmental conditions, coated with different anti-corroding agents, and subjected to different temperatures and pH values. Five Different environmental conditions through which pipelines are laid (Top soil + Fresh water, Sea water bed sand + Sea water, Lagoon water, Seawater, NaCl solution (0.5M)) were simulated in the laboratory. Different seventy gram (70g) samples of the carbon steel pipeline were used as the coupon samples. Red oxide oil paint and tar paint were used as the anti-corroding agents. Water bath was used in regulating the temperature and different concentration of HCL and NaOH were used to vary the pH. Weight loss method was used to calculate the corrosion rates.\u0000 Results show that carbon steel resists corrosion better when buried in soil than when submerged in water; also the corrosion rate is more in sea water than in the lagoon water of relatively smaller salinity. The rate of corrosion was observed to increase with: increase in temperature, increase in salinity, and increases in acidity and alkalinity. Also the tar paint is more effective as anti-corrodant than the red oxide oil paint when applied to the carbon steel pipeline under same environment conditions. The study successively reduced the corrosion rate of the 70g coupon sample from 0.00127g/day when the sample were suspended in 0.5M, NaCl solution to 0.000104g/day when pipeline coated with tar paint are buried in dry soil.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81868555","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Egina Deep Water Development: Isolation Barrier Valve Case Study","authors":"G. Forrest, Christophe Morand, Kenneth Johnson, V. Okengwu, V. Chaloupka","doi":"10.4043/28453-MS","DOIUrl":"https://doi.org/10.4043/28453-MS","url":null,"abstract":"\u0000 A major operator manages multiple deep water projects in the Gulf of Guinea. This paper describes the latest 44-well project in Nigeria. The operator required an ISO 28781 qualified bi-directional subsurface isolation barrier valve (IBV) (Fig. 1) to be installed in each well. This work presents results of IBV deployment in the field.\u0000 The wells were drilled and completed from sixth generation drillships. To comply with the operator's dual barrier policy, a bi-directional IBV was installed in each well to help ensure reservoir isolation for temporary well suspension or before running upper completion and tree installation. Careful attention to well fluid cleanliness, sound quality assurance/quality control (QA/QC), and operational procedures were considered paramount to successful remote opening of the IBVs and were identified as best practices by both parties.\u0000 The IBV is run in the open position as an integral part of the lower completion. A collet shifting tool closes the ball isolating the formation, enabling inflow and positive pressure testing to be performed. The reservoirs are isolated by the closed ball in the IBV, allowing safe installation of the upper completion from a floating rig or well suspension without a subsea tree. The use of an ISO 28781 Type CC V1 qualified IBV provides both zonal isolation and fluid-loss control. Once a well is completed and the subsea tree installed, the IBV is remotely functioned to the open position by applying multiple tubing pressure cycles.\u0000 The first batch of wells were drilled and completed with lower completions and suspended while waiting for subsea tree deliveries. Later, wells were drilled and completed with both lower and upper completions, and trees were installed later from an offshore inspection maintenance and repair (OIMR) vessel. IBVs were successfully closed and inflow and pressure tested during the lower completion phase.\u0000 IBVs are run in sieved non-aqueous based mud (NABM). Filtered high viscosity pills are spotted across the IBV before closing. Once closed, the casing above the IBV is displaced to filtered completion brine at a rate ensuring any debris is lifted to the surface. The wells remain suspended with IBVs closed until the operator performs flowback and injectivity testing from a drillship. Additional injectivity testing was also performed from an OIMR vessel. Well suspension duration with IBVs closed varied between two months and 2.5 years. All valves cycled opened without issues. Four coiled tubing (CT) interventions were performed in the field, passing through the open ball without issue, confirming the IBVs were in the fully open position.\u0000 This paper describes full QA/QC and operational procedures, which led to successful deployment and excellent functionality of the IBVs.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-03-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86033885","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}