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The objective of this study was to characterize formation water resistivity (
A database with analyzed water sample and log-derived (Dielectric and Conventional logs)
Creating the WSA tool was very important to determine which samples were ionic balanced and were useful for further steps. These samples delivered different salinities which could clarify the water sources for the produced sand intervals. Three main groups of water sources were established based on the salinity; S-sands, T-sands and Cretaceous. Based on this classification, the log derived
Regarding stock tank oil initially in place (STOIIP) in TCA, with the variable
Formation water salinity is a very important input in
Mustapha, Adetoun (Shell Nigeria Exploration and Production Company Limited) | Afuba, Paul (Shell Nigeria Exploration and Production Company Limited) | Enechi, Felicia (Shell Nigeria Exploration and Production Company Limited) | Ejiofor, Chiedu (Shell Nigeria Exploration and Production Company Limited) | Olasubulumi, Akintunde (Shell Nigeria Exploration and Production Company Limited)
The most complex and largest Turnaround Maintenance (TAM) in the history of the Shell Nigeria Exploration and Production Company's Bonga asset was completed in April 2017. Strategic value drivers were Statutory/Regulatory, Asset Integrity, Relief Valve(RV) Recertifications, Vessel Cleaning and Upgrades. Often, Turnaround management has huge impact and directly contributes to the company's bottom line profits. However, controlling turnaround costs and duration represent a definite challenge.
This paper presents the structured process of managing the TAM project and key lessons learnt on integration with its attendant impact on project delivery. The turnaround comprises over three hundred Operations, Maintenance and Project scopes. Over ten in-field vessels were deployed, including a 600-bed Floating accommodation vessel, and over 50 Nigerian contractors and sub-contractor companies were involved while over 2,000 material deliveries were required. The workforce was over 1,000 people that cuts across 10 Functions, several Disciplines, diverse culture and mixed genders; and spread across locations. Team effectiveness and integration were identified as key elements for the team to complete the scope safely, within budget and on schedule.
Overall, several challenges were encountered during the TAM; and interventions were implemented to deepen end-to-end thinking, make performance on integrated key performance indicators visible and rally the teams to get critical steps right. This paper shares learnings on how the team was orchestrated to develop shared goals, common understanding of processes and appropriate behaviours and work effectively across organizational boundaries as ONE team. The critical scopes were delivered on schedule and below budget. The TAM therefore resulted in increased asset reliability, continued production integrity, and significantly reduced the risk of unscheduled outages or production deferments.
Dinh, Chuc Nguyen (PetroVietnam Exploration Production Corporation) | Nhu, Huy Tran (PetroVietnam Exploration Production Corporation) | Thanh, Ha Mai (PetroVietnam Exploration Production Corporation) | Viet, Bach Hoang (PetroVietnam Exploration Production Corporation) | Van, Xuan Tran (Ho Chi Minh City University of Technology, VNU-HCMC) | Thanh, Tan Mai (Ha Noi University of Mining and Geology)
Cuu Long basin is a Cenozoic rift basin located in the southeastern shelf of S.R. Vietnam, containing vast potential oil and gas resources. The basin was impacted by three main tectonic periods of pre-rift, syn-rift and post-rift tectonism. Major petroleum plays in Cuu Long basin are the Pre-Cenozoic fractured basement, Oligocene and lower Miocene sandstone reservoirs. Upper Oligocene sediments were deposited during late syn-rift phase of Cuu Long basin. The reservoirs in these strata (Oligocene C and D) were previously discovered in the center, southwestern and southeastern margins of Cuu Long basin with limited total reserves, up to 5%, of Cuu Long basin's discovered reserves. Recent exploration and appraisal results of St, Tg, Rg, Ct etc. show a greater potential of upper Oligocene reservoirs with a greater variety of trap types in many areas of Cuu Long basin than that of previous assessments. Therefore, additional studies and assessments of recently discovered trap types need to be carried out for the Cuu Long basin exploration and appraisal program. This article discusses the assessments of upper Oligocene trap types and identifications of several trap mechanisms utilizing the integration of exploration methods. The research results permit better understanding of the trapping mechanisms and possible distributions of various trap types in the upper Oligocene strata of the Cuu Long basin, thus leading to better planning of exploration/appraisal strategies in the basin.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169978, “Case Study for Reducing Tubing Failures in Suriname’s Tambaredjo Field,” by D. Nurmohamed, SPE, H. Chin A Lien, SPE, and S. Kisoensingh, SPE, Staatsolie Maatschappij Suriname, prepared for the 2014 SPE Trinidad and Tobago Energy Resources Conference, Port of Spain, Trinidad and Tobago, 9–11 June. The paper has not been peer reviewed.
In the 30 years of operations on Suriname’s Tambaredjo field, the prime mechanism for lifting the 15.6 °API crude to surface has been that of progressing cavity pumps (PCPs). In the period from 2008 to 2012, an annual average of 580 downhole failures occurred, 54% of which were caused by tubing leaks. In an effort to reduce these tubing failures, a pilot program was commenced to install rod guides in wells with the highest failure rate and to install a 25-ft sucker rod directly above the pump.
Currently, Staatsolie Maatschappij Suriname produces from the Tambaredjo, Calcutta, and Tambaredjo Northwest fields, as illustrated in Fig. 1. These oil fields are located in a marshy area on the coastal plain of Suriname approximately 55 km west of Paramaribo.
The crude oil contains low sulfur content (0.65 wt%) and 1 wt% asphaltene and has an average viscosity of 500 cp at reservoir conditions. The water/oil ratio is 7 and the gas/oil ratio is less than 50 scf/bbl as of December 2013. The average daily production from these fields reached 16,700 BOPD from 1,549 active producing wells completed in shallow unconsolidated-sand reservoirs with depths ranging from 700 to 1,500 ft. The Tambaredjo oil field is the oldest and largest of these fields, with 1,130 active producers contributing two-thirds of the overall production.
Mechanical Wear of Tubing
The majority of tubing failures in the Tambaredjo field are repetitive in nature. Mechanical wear is the removal of metal caused by the frictional rubbing of the sucker-rod string against the inner wall of the tubing. This frictional rubbing can be increased by the movement of the rod string, often characterized as stick/slip.
Currently, Staatsolie Maatschappij Suriname produces from the Tambaredjo, Calcutta, and Tambaredjo Northwest fields, as illustrated in Figure 1 above. These oil fields are located in a marshy area on the coastal plain of Suriname approximately 55 km west of Paramaribo. The crude oil contains low sulfur content (0.65 wt%) and 1 wt% asphaltene and has an average viscosity of 500 cp at reservoir conditions. The water/oil ratio is 7 and the gas/oil ratio is less than 50 scf/bbl as of December 2013. The average daily production from these fields reached 16,700 BOPD from 1,549 active producing wells completed in shallow unconsolidated-sand reservoirs with depths ranging from 700 to 1,500 ft. The Tambaredjo oil field is the oldest and largest of these fields, with 1,130 active producers contributing two-thirds of the overall production. This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169978, “Case Study for Reducing Tubing Failures in Suriname’s Tambaredjo Field,” by D.
Heavy oil refers to oils having an API gravity lower than 20° and viscosity at formation conditions above 100 centipoise (cp). These hydrocarbons generally pose challenging production problems and are marketed at a discounted price. However, the combination of improved technology and higher oil prices make the exploitation of heavy-oil deposits more economically feasible. Besides the quantity of production and processing problems associated with heavy oils, evaluating petrophysical properties from nuclear magnetic resonance (NMR) logging measurements can be problematic because of a number of issues, such as heavy oil NMR responses are similar to signals from capillary-bound water.
Additionally, heavy-oil chemistry can be conducive to a wettability alteration that can lead to a misinterpretation of water content from conventional and NMR logs. These phenomena make it difficult to quantify and type fluid volumes in heavy-oil reservoirs from NMR measurements alone.
NMR logging instruments sometimes do not fully capture heavy-oil signals because they operate at inter-echo spacings that make them unable to adequately sample important rapid decay components when viscosity exceeds ~1000 cp. This situation causes the indicated NMR porosity to be somewhat small, as though the reservoir fluid had a hydrogen index (HI) smaller than one, as occurs in gas reservoirs.
These factors make it necessary to apply advanced interpretation methods to find indications of altered wettability and evaluate petrophysical quantities, such as fluid volumes, permeability, and apparent in-situ oil viscosity.
The method consists of combining NMR and conventional wireline logs to measure the signal loss and estimate the oil’s viscosity where the in-situ viscosity is larger than a few hundred cp. Additional combinations with conventional logs can be formed with NMR diffusion measurements to infer movable and capillary-bound water volumes. These volumes can then be used to refine interpretations of resistivity logs, indicate altered wettability, and provide an improved estimate of permeability in heavy-oil reservoirs.
This paper shows the validation of this method implemented in over 20 wells in the Suriname-Guyana basin. The average well depth is approximately 1,000 ft, bottomhole temperature (BHT) is ~100°F, and gravity is in the range of 10 to 20 API. The results are validated with production data.
In Staatsolie, as of December 2013, there were 1549 shallow wells from its 3 oilfields. One thousand one hondred and thirty (1130) of these were in the Tambaredjo field (TAM field). In the 3 decades of its operations, the prime mechanism for lifting the 15.6oAPI crude to surface has been with progressive cavity pumps (PCP). The down hole pumps are surface driven and installed at an average true vertical depth (TVD) of 1000 ft. Oilfield best practices are employed in the design, installation and operation of the production strings and pumps.
In the period 2008-2012 an average 580 down hole failures occurred annually of which 54% was caused by tubing leaks, with a repetitive frequency of up to 6 faillures per year on individual wells. Visual inspection of internal tubing’s have shown that the principal failure mechanism stems from rod tubing wear (abrasion caused by the rotational motion) exacerbated by the corrosiveness of the produced fluids. Most of the tubing wear occurs at the tubing body in direct contact with the rod couplings. It is found that most tubing leakages (up to 70%) occur on the lower part of the tubing string above the pump. Previous installation of shorter rods above the pump, which is causing a high eccentrically movement of the rod string, also increased the occurrences of these failures directly above the pump.
In an effort to reduce these tubing failures, an eight-well pilot program was commenced to install rod guides in wells with the highest failure rate and to install a sucker rod of 25 feet right above the pump. These eight wells were selected based on their high tubing failure rates. Although the program is still being conducted, preliminary results thus far have been quite promising in these wells. In four (4) wells, the work-over frequency was reduced from average 5 to 3 jobs per annum resulting in 40% reduction. The remaining 4 wells are still producing after an average 5-month period without any tubing failures.
This paper presents the approach and strategy used to minimize rod-tubing wear in shallow vertical well applications based on the outcome of the pilot test.
To date some 1,500 Progressive Cavity Pumps (PCP) are utilized for artificial lifting of averagely 15.6 API0 crude oil with average viscosity of 500 cp at reservoir conditions, from the Staatsolie wells to the treatment facilities. The single lobe pumps are installed at an average depth of 1000 ft, producing from unconsolidated Tertiary sand reservoirs with rates varying from 10 up to 2000 barrels BFPD.
The shift from pumping jacks to PCP's was made in the mid 80's due to the flexibility and improved efficiency in drivehead configuration as well as volumetric efficiency of the PCP system contributing to significant reduction in lifting cost per barrel fluid. The PCP has established its robustness being in operations for almost 30 years under varying well conditions such as increasing water-cuts and fluid production rates, decreasing reservoir pressures, fluctuating GOR's and in vertical as well as in approximately 500 deviated wells.
Pump stator material, by default nitrile based, has been fabricated to suit the low aromatics content in the crude. Typical stator failures encountered include cracks and blistering combined sometimes by pitting and abrasion. The Mean Time Between Failure (MTBF) ranges from 2 months to almost 25 years.
In 2008, the Nodal Analysis concept was introduced to compare IPR and VLP for optimization purposes. VLP curves were created by modeling the PCP as two tubes, for which the inner tube would represent the annular flow between the pump helical rotor and stator and outer tube for the rod-tubing flow. An advancement that allowed the user to select the appropriate pump based on required pump differential pressure. CFER well modeling for pump seating, hydraulic torque, rod-tubing contact, rod string as well as rod-tubing loads were analyzed and optimized for given wellbore trajectory and doglegs.
The paper presents the versatility of the PCP application in different downhole environments, the performance and challenges to mitigate the common failures. Results of field cases and software simulations will be presented for best practice recommendations for progressive cavity pump applications in shallow heavy oil reservoirs.