Well integrity is a key focus area in any oil and gas development. There have been several cases of well integrity issues which have resulted in scenarios of blowout, loss of lives, assets, and reputation, including costs spent for clean-up and environmental remediation, amongst others. These and more have made the energy industry put a keen focus to making sure all hydrocarbon production and processing facilities are integral, with newer technologies still being developed to aid the diagnosis of well integrity problems. Well integrity considerations cut across the entire life cycle of the well, from well conceptualization/planning through to drilling, completion, production and abandonment. This case study presents a high-pressure, high temperature gas well with sustained annulus pressure in the early production phase of the well. Well X is a gas well completed in an elevated pressure and temperature reservoir on a land terrain. The reservoir is about 13000ftss deep, with a temperature of 219°F and a reservoir pressure of 9300psi. The well was completed, cleaned up and brought to production about a year ago and annular pressures were observed. This paper details the different approaches used in diagnosing the sustained annular pressures – separating thermal effect from sustained pressure due to leak. It shows the different scenarios of leak paths identified and how these were streamlined. The paper also highlights the integration of data acquired during the investigation. Some of the data acquired include well annuli pressures, high precision temperature logs, spectral noise logs and electromagnetic corrosion logs.
This paper provides an insight into the gains and realism injected into life cycle resource estimation of a gas cap reservoir slated for gas cap blown in 2030. Proper data integration spanning from subsurface to surface cannot be over emphasized as the major trigger for the successful estimation of the life cycle resource in this reservoir alongside a realistic execution time line for the gas cap blow down project. One major consideration in the evaluation of gas cap blowdown projects is the efficient and maximal recovery of the oil rim available and the subsequent prediction of the gas cap blow down on stream phase while complying with statutory promises. A major enabler to achieving this objective in the ZN reservoir was the ability to harness and integrate available shared critical data from the subsurface, production, studies team, forecasting team, facilities and concept engineering teams in a pragmatic and cost effectively manner. The ZN is the largest gas cap reservoir in the X-Onshore field. Current STOIIP is 320MMstb and GIIP is 1.4 TCF. The reservoir started production 21 years ago and a total of 13 oil wells have produced from this reservoir with two gas wells proposed to be used in the blow down of the gas cap at a future date. Cumulative oil production so far is 46MMSTB and 157BSCF AG which translates into a current oil RF of 14%. Accurate estimation of the Gas Cap Manifold Inlet Pressure, the Gas Cap blow down on stream dates and project prioritization were key factors required for the proper prediction of the life cycle resource for this reservoir. This paper seeks to describe how effective the process of proper data integration has been in assisting the delivery process that has translated into a more realistic and robust gas cap blow down time line and resource evaluation that synergizes with the stakeholders growth aspirations.
Beta Integrated Oil and Gas plant is the major supplier of domestic gas to the Lima power plant which provides 16% of the available power to the Nigerian national grid. Efforts are made to ensure that down times in the plant are reduced because of the huge impact to domestic gas supply in the country. Between 2014 and 2015, multiple tripping had been observed on the transfer pump at the Beta gas plant. Laboratory analysis of the recovered solid deposits in addition to scale simulations of the hydrocarbon fluid confirmed the presence of calcium carbonate scale (85.2%wt). Although the culprit well was identified, a cost-effective surface chemical solution was immediately deployed upstream of the facility which significantly reduced the export pump downtime due to scaling and clogging. The overall treatment option adequately mitigated the calcium carbonate scale observed and also led to significant savings in pump maintenance of about a million dollars. This paper will be discussing the problem and underlying restrictions faced by the multidisciplinary team, problem solving approaches considered as well as the solution employed by deploying Phosphate Ester based chemical scale inhibitor. The scale inhibitor is specially formulated to prevent the formation of calcium carbonate, calcium sulphate, barium sulphate and strontium sulphate scales in producing wells, water injection systems and saltwater disposal systems. One major consideration in the choice and use of the product is the cost effectiveness of the product, its potency and suitability at effectively mitigating the calcium carbonate scaling in the gas plant. It was successfully qualified in the lab for use with MIC of 10-20ppm and has been previously deployed in our deep water facility. Laboratory tests indicate it is effective in produced water with iron and high bicarbonate content as is the case for Beta gas plant. In addition, laboratory tests indicate it does not encourage deposition of naphthenates in produced water as is observed with some phosphate based scale inhibitors. The product is also readily available in-country hence no long delivery lead time challenges, besides there is significant cost and logistics value to be realized from its deployment in Beta oil and gas plant.
The GBN NAG reservoir development project is part of the GBNRC Phase 1-6 project which involves the development of 6 wells with the potential to deliver additional 410MMscf/d to the GBNRC export gas market. The wells were drilled with heavily weighted POBM at 0.68 – 0.72 psi/ft. The lower completion was ran with the heavily weighted mud in hole and isolated with a Formation Isolated Valve (FIV) while the upper completion was completed with brine at 0.48 psi/ft. The wells were completed with 7" 13 Cr tubing, Reslink as sand control with potential of 120 MMscf/d each from each well. Post clean up and Multi Rate Test activities some of the wells were observed to produce with drawdown higher than the acceptable limit therefore necessitating the reduction of well potential to adhere to the draw down limit and prevent possible well integrity incident. The team was therefore charged with the responsibility to proffer feasible well intervention options in a High-Pressure environment to restore full wells potential of 410MMscf/d at the most economical way possible without compromising on safety and well integrity. This paper documents the integrated approach taken by the team to identify the cause of high drawdown in these wells, feasible intervention options and selection criteria leading to restoration of planned potential therefore meeting up company obligations to GBNRC supply and preventing possible well integrity incident in these wells.
Gas reservoir development at inception is often linked to detailed surface infrastructure development and long term contractual agreements with only a few appraisal wells. A thorough and detailed technical estimation of the size of the pie is an important step in the right direction. This is characterized by seismic acquisition and interpretation, scanty appraisal wells proving useful reservoir and fluids properties data and contact tagging. Calibration of regional properties with nearfield analogue can also be quite useful. All these form the basis of the field/Reservoir development plan. For a gas development, the optimum development wells depend on a variety of factors identified at the field development stage often targeting the most viable crestal part of the reservoir for optimal development. Post drilling of development wells where reservoir static properties are fairly known and at the early stage of production when there is paucity of production data, it is imperative to adopt a robust approach to evaluate the technical UR. In early producing life of the reservoir when reservoir pressure data is needed perhaps the most, long shuttin-in to take static pressures can be abit problematic due to commercial commitments. There is heavy reliance on planned and unplanned shutins to take useful pressure data used in calibrating reservoir models. This paper takes a critical look at multiple approaches to estimating robust ultimate recoverable gas volumes with reservoir geology as an essential guide using tow distinc approaches; Detailed 3D simulation model and P/Z estimate method using Piper, McCain and Corredor z factor estimates. Lastly the range of uncertainties of the input data was used to estimate the low base and high cases.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.