DeepStar case study: flowline burial for insulation

2010 ◽  
Vol 50 (2) ◽  
pp. 684
Author(s):  
Tommy Golczynski
Keyword(s):  
Net Present Value ◽  
Oil And Gas ◽  
High Water ◽  
Gas Production ◽  
Added Value ◽  
Successful Implementation ◽  
Upheaval Buckling ◽  
High Pressure High Temperature ◽  
Scope Of Application ◽  
Water Rate

Canyon Offshore, Multiphase Solutions and ASGM Engineering recently completed a study for DeepStar to assess flowline burial for insulation for oil and gas deepwater subsea tiebacks with high-pressure/high-temperature (HPHT) reservoir characteristics. The primary goal of the study was to document the scope of application, added value, and schemes for successful implementation of burial for insulation of deepwater HPHT flowlines. The prize in oil production is the extended cool-down time (three plus days), which can potentially reduce the number of occasions where flowline cold shut-in preparations are necessary. The principal prize in gas production is ability to deliver high water-rate gas production, by removing the need for continuous hydrate inhibitor and extending production beyond the point where inhibitor delivery is inadequate. Lateral and upheaval buckling analyses assessed the expected interaction between flowline, soil and movements associated with expansion due to temperature. Controlled installation sequencing to allow for lateral buckling during the initial startup phase was evaluated to mitigate the risk of excessive bending strains and upheaval buckling in the flowline from thermal expansion. The results indicate installation methodologies can achieve reduced bending strains and avoid upheaval buckling. Net present value (NPV) calculations were tabulated for the various tieback scenarios to assess the economic merits of flowline burial versus non-burial. The results of the study indicate that burial provides improved thermal insulation characteristics and yielded positive NPV, compared to unburied flowlines. The risk of thermal-induced lateral and upheaval buckling can be mitigated using identified techniques during the installation phase of the work to avoid undesired high bending strains.

Development and Execution of Heritage Petroleum Company Limited’s First Offshore Workover Campaign - A Case History of Successful Implementation of Performance Management

2021 ◽  
Author(s):  
Shazim Mohammed ◽  
Dale Persad ◽  
Kirk Baksh
Keyword(s):  
Trinidad And Tobago ◽  
Performance Management ◽  
Net Present Value ◽  
Oil And Gas ◽  
Selection Process ◽  
Public Procurement ◽  
Dynamic Modelling ◽  
Successful Implementation ◽  
Procurement Process ◽  
Petroleum Company

Abstract Heritage Petroleum Company Limited (HPCL) is the newest operating oil and gas company in Trinidad and Tobago and was vested and entrusted with the operation and management of all the exploration and production assets of Petroleum Company of Trinidad and Tobago Limited ("Petrotrin"). Being driven by oil-based revenue meant that rig intervention projects had to be innovative, economically viable and practical to meet the company’s financial commitments. This paper presents the concepts and processes behind the development and implementation of HPCL’s Workover Scoping and Procurement Framework. The offshore team recognized the need to frame the well review and workover candidate selection process as well as a procurement process that was both operationally accommodating and in accordance with public procurement regulations. This process would also have to be tested, since it was a new concept that was not practiced by Petrotrin. The well review process involved defining reservoir deliverability and in-place volumes through static and dynamic modelling, establishing current well potential and deliverability via nodal analysis with installed completion designs, topside infrastructure conditions and flow restrictions. The procurement process was achieved by identifying local resources and generating framework agreements for services and equipment. Job specific resources were tendered to ensure a transparent selection and award. The process also involved ranking the risks of all candidates. Economic analyses were performed to determine whether the financial indicators were positive to ensure viability of the campaign. A scorpion plot was also used to manage the performance of this framework during the campaign. The result was a campaign consisting of 15 wells that was delivered on time and within the workover budget. Actual production gain was over 1700 BOPD as opposed to the expected gain of 1450 BOPD. Budgeted Net Present Value (NPV) and actual NPV was calculated to be US$ 9.42 million dollars and US$ 11.7 million dollars respectively. All resources were demobilized and removed from the offshore acreage to reduce risks and floating expense to the company at the end of the campaign.

scholarly journals Dual hydrocarbon–geothermal energy exploitation: potential synergy between the production of natural gas and warm water from the subsurface

2019 ◽  
Vol 98 ◽  
Author(s):  
Jeroen van der Molen ◽  
Elisabeth Peters ◽  
Farid Jedari-Eyvazi ◽  
Serge F. van Gessel
Keyword(s):  
Natural Gas ◽  
Financial Risk ◽  
Net Present Value ◽  
Gas Production ◽  
Added Value ◽  
Reservoir Properties ◽  
Gas Field ◽  
Gas Recovery ◽  
Water Breakthrough ◽  
High Standards

Abstract The decline of domestic natural gas production, increasing dependency on gas imports and lagging development of renewable energy production may pose serious challenges to the current high standards of secure energy supply in the Netherlands. This paper examines synergy between hydrocarbon- and geothermal exploitation as a means to reinforce energy security. The Roden gas field is used as an example to demonstrate potential delay of water breakthrough in the gas well and a resulting increase of recovered gas (up to 19%), by positioning of a geothermal doublet in the water leg of the gas field. The reservoir simulations show that the total increase of gas production primarily depends on the amount of aquifer support. An optimal configuration of gas- and geothermal wells is key to maximise gas recovery and strongly depends on the distribution of reservoir properties. The study also reveals that this option can still be beneficial for gas fields in a late stage of production. Net Present Value calculations show that the added value from the geothermal doublet on total gas production could lead to an early repayment of initial investments in the geothermal project, thereby reducing the overall financial risk. If no subsidies are taken into account, the additional profits can also be used to finance the geothermal project up to break-even level within 15 years. However, this comes with a cost as the additional profits from improved gas recovery are significantly reduced.

scholarly journals Diagnosing High Water Production in Kalama Field, Niger Delta

2021 ◽  
pp. 18-26
Author(s):  
Amieibibama Joseph ◽  
Friday James
Keyword(s):  
Niger Delta ◽  
Oil And Gas ◽  
Produced Water ◽  
High Water ◽  
Gas Production ◽  
Water Production ◽  
Oil And Gas Production ◽  
Excess Water ◽  
High Water Cut ◽  
The Impact

Produced water is water trapped in underground formations that is brought to the surface along with oil or gas. It is by far the largest volume by-product or waste stream associated with oil and gas production especially in brown fields. Management of produced water present challenges and costs to operations. In this paper, the possible causes, effects and solutions of high water-cut is being investigated in some production oil wells in Niger Delta, using Kalama field as a case study. Diagnostic and performance plots were developed in order to determine the source of water as well as to evaluate the impact of excess water production on oil production and in field economics in general. Results obtained from the diagnostic plots showed the possible sources of water production are channeling behind casing and multi-layered channeling. The recommended remediation is cementation through a workover operation. Also, a concise step to be taken for identifying excess water was also developed in this work to effectively control excess water production in oil producing wells.

FAILURE TO ACHIEVE PLANNED ECONOMIC PERFORMANCE OF OIL AND GAS PRODUCTION PROJECTS DUE TO LACK OF RISK ASSESSMENT AND UNCERTAINTY QUANTIFICATION

2020 ◽  
pp. 75-80
Author(s):  
M.Y. Nazarenko ◽  
A.B. Zolotukhin
Keyword(s):  
Economic Efficiency ◽  
Economic Performance ◽  
Quantitative Assessment ◽  
Net Present Value ◽  
Oil And Gas ◽  
Gas Production ◽  
Internal Rate Of Return ◽  
Present Value ◽  
Oil And Gas Production ◽  
Predicted Values

Quantitative assessment of risks and uncertainty has always played the most important role in the evaluation of oil & gas projects. Any estimated, measurable or evaluable magnitude contains an uncertainty, whether it concerns measuring watercut by means of a multiphase flow meter (MPFM) or to the net present value (NPV) of a major E&P project. Evaluation of project economics, e.g. the calculation of net present value (NPV), internal rate of return (IRR), OPEX and CAPEX shall be probabilistic, i.e. carried out with the quantitative assessment of risks and uncertainty of estimated (predicted) values. Nevertheless probabilistic estimate takes place very rarely. Most commonly, assessment of risks and uncertainty would be intuitive or based on a number of deterministic scenarios mistakenly referred to as pessimistic, optimistic and most probable. This research simulates failure to achieve target economic efficiency of E&P projects with no quantitative assessment of risks and uncertainty, and reviews previous international research conducted to identify the effect of ignoring probabilistic estimates related to the evaluation of E&P projects on their final economic efficiency.

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