Export Pipeline Research Articles

UPDATED MATHEMATICAL MODEL OF THE TRUNK PIPELINE SECTION WITH LOOPING IN CASE OF LEAKAGE

Pipeline transport is the main method of moving volumes of oil and oil products, as it has several advantages, for example, quality safety and high throughput. At the same time, it also has some disadvantages, which can include the difficulty of increasing throughput without high capital investments and possible leaks and unauthorized tie-ins into pipelines, which are sometimes difficult to identify. Looping is one of the main ways to increase the throughput of the existing pipeline system, when the need to increase the volume of oil and oil products supplies requires the construction of several parallel pipelines — looping. At the same time, the basic mathematical model for calculating the section of the trunk oil pipeline with looping does not fully cover all the physical processes associated with the distribution of flows in the parallel section, which arise due to turbulences in the connection nodes, as well as head loss along the length of the jumpers. Taking into account the resulting flow redistributions, it becomes difficult to detect a potential leak, since any of the detection methods can not solve the problem with high accuracy with determining the leak coordinate with an unknown distribution of fluid flow rates in a parallel section. As part of the study, an updated mathematical model of the oil export pipeline section with looping was developed, which took into account the presence of a potential leak in the parallel section. Mathematical modeling was carried out on the basis of the assumption of a known coordinate, the effect of leakage on the redistribution of flows in a parallel section was estimated. To assess the impact of the leak, various coordinates and volumetric flow rates were set, based on the calculation results, graphs of the flow rate in looping versus its length and internal diameter were plotted. The study is the initial phase of developing a hydraulic location leak detection system for the oil export pipeline section with looping. The need to refine the mathematical model for determining the flow rate in the parallel section is an urgent and necessary task, the solution of which will allow identifying potential leaks with reliable accuracy.

Bottom-up formulations for the multi-criteria decision analysis of oil and gas pipeline decommissioning in the North Sea: Brent field case study

Many Oil and Gas (O&G) fields in the North Sea have produced their economically recoverable reserves and have entered the decommissioning phase or are close to cessation of production. The subsequent O&G decommissioning process involves a range of stakeholders with specific interests and priorities. This range of inputs to the process highlights the necessity for the development of multi-criteria decision frameworks to help guide the decision-making process. This study presents bottom-up formulations for the economic, environmental, and safety risk criteria to support the multi-criteria decision analysis within the Comparative Assessment (CA) of O&G pipeline decommissioning projects in the North Sea. The approach adapts current guidelines in the O&G industry and considers a range of parameters to provide estimations for the costs, energy usage, greenhouse gas emissions, and safety risks. To verify the effectiveness of the proposed bottom-up formulations, the longest oil export pipeline in the Brent field, PL001/N0501 is selected as a case study. The numerical results revealed the consistency of the results obtained from the proposed approach with those reported in the technical documents by industry. In most cases, the formulations provide estimates with less than 10% differences for the costs, energy usage, emissions, and safety risks. Based on the proposed multi-criteria formulations, the study also presents the use of an immersive decision-making environment within a marine simulator system to help inform the decision-making process by stakeholders.

A path to make well-informed decisions when considering the decommissioning of subsea pipelines

Australia’s law mandates the removal of infrastructure once not in use unless the Titleholder can demonstrate an equal or superior safety and environmental outcome. Around 100 infield and export pipelines in Australian waters, with an approximate total length of 5000 km, are nearing their end-of-life period. Three common decommissioning options are considered for subsea pipelines: complete removal, partial removal, or in-situ abandonment. Decommissioning these pipelines will cost an estimated US$13 billion, ~33% of the cumulative Australian offshore decommissioning liability, should the full removal option be selected. When decommissioning subsea pipelines, it is essential to consider that they have been exposed to hazardous fluids and aggressive environments. Careful assessments should determine the recyclability of recovered materials, decontamination, and the environmental risks associated with each decommissioning option. A holistic approach is needed to identify and quantify contaminants in subsea pipelines. In the early stages of decommissioning, planning, sampling, and laboratory testing are necessary to identify plastic coating types, degradation mechanisms, constituents released to the environment, types and mechanisms related to mercury/naturally occurring radioactive materials, and chemical stability. This paper aims to identify and present effective methods for addressing the impact of pipeline constituents on the Marine Environment Assessment while assessing potential decommissioning options and explains how tools can support decision-making. In summary, decommissioning subsea pipelines requires careful assessment and planning to ensure environmental and safety compliance. The paper provides a guide to understanding the process, highlighting the importance of quality assurance, risk assessment, and the selection of appropriate decommissioning options.

EXTERNAL FACTORS OF RUSSIAN ENERGY SECTOR DEVELOPMENT: OPPORTUNITIES AND RISKS IN THE NEW GEO-ECONOMIC REALITY

The paper analyzes the main stages of the Russian energy sector development in the context of the influence of external factors. The author considers the role of the new export pipelines construction in strengthening the country’s position in global energy markets. The article provides an assessment of the dependence of Russian energy sector on foreign capital and technology. The author provides some practical recommendations for the development of the Russian energy sector in the context of Western sanctions and the transition to a low-carbon economy.

ANALYSIS OF EXTREME VALUES FOR DATA PROCESSING OF IN-LINE TECHNICAL DIAGNOSTICS

The pipeline system plays an important role in the structure of enterprises engaged in the transportation of significant volumes of oil and gas over long distances. However, steel pipelines are subject to corrosive factors, which can lead to defects and a reduced service life. Statistical analysis methods have recently been increasingly used to maintain structural reliability and ensure safe operation of equipment, both in the oil and gas industries. One method of statistical modeling is extreme value analysis, which can be used to extrapolate data from random inspection checks to non-investigated areas. The article is devoted to the assessment of the possibility of using statistical methods for analyzing data of in-line technical diagnostics (ITD) to ensure the integrity of trunk pipelines. The ITD results of one section of the export pipeline were used to determine the maximum corrosion rate of the entire length of the pipeline by extrapolating the Gumbel statistical distribution. The algorithm for constructing the Gumbel distribution is given. Plotting the autocorrelation function was used as a method for determining the independence of measurements. The belonging of the analyzed sample to the Gumbel distribution was confirmed by calculating the Anderson-Darling consent criterion. The ITD results of the remaining sections of the oil export pipeline confirmed the possibility of using extreme analysis to determine the maximum corrosion rate and increase the efficiency of pipeline inspection measures. Thus, it was concluded that statistical modeling is able to provide an estimate of the maximum corrosion rate during partial pipeline ITD and, therefore, savings in financial and time resources.

Dynamic Probabilistic Risk Assessment of Overpressure Burst of Pipeline with Pressure-Protection Systems in Case of Blockage

Although overpressure burst of pipeline with pressure-protection systems occurs infrequently in case of blockage, it endangers personnel safety and causes serious economic loss when it happens. Therefore, assessing the dynamic probabilistic risk of overpressure burst of pipeline with pressure-protection systems in case of blockage is necessary to prevent accidents. This study proposes a method based on a dynamic Bayesian network (DBN) for assessing the dynamic probabilistic risk of overpressure burst of pipeline with pressure-protection systems in case of blockage. First, a fault tree (FT) model of pipeline overpressure burst is constructed. The constructed FT model is then mapped into the DBN model to solve the uncertainty of the model. Second, the leaky Noisy-OR gate is used to define the uncertain logical relationships of relevant nodes in the DBN model. The effect of common cause failures on a pipeline’s redundant pressure-protection system is analyzed using the multiple error shock model. Finally, a natural gas export pipeline is presented as an example to demonstrate the proposed method. Results show that the method can effectively assess the dynamic probabilistic risk of overpressure burst of pipeline with pressure-protection systems in case of blockage.

Re-purposing onshore and offshore infrastructure for CCUS in Gippsland

With the race to decarbonise in full swing how do carbon capture utilisation and storage (CCUS) projects get a head start? This paper explores the journey the Gippsland Basin Joint Venture has gone through to identify and exploit the advantages that its existing infrastructure presents in order to progress world-class CCUS opportunities. Drawing on examples across the full CO2 supply chain it details how re-use of existing infrastructures can achieve positive results in terms of cost, schedule and the environment. Hydrocarbon production from the Bream Field ceased in 2020. Normally this would put the platform and associated infrastructure on the path to decommissioning and removal. Instead Bream will continue to have a bright future storing CO2 supplied via a re-used gas export pipeline. Technical evaluations have considered how to safely handle CO2, what parts of the asset could be re-used, what new kit is required and what should be decommissioned. Powered by a hybrid renewables system the new-look injection platform will be remotely operated storing up to 2 MTA. At the Longford Gas Plant the focus has been how to efficiently capture CO2 in order to meet the requirements of multiple purification plants and the Bream sequestration project. Plant trials and testing have determined how to optimise gas processing for integrated CCUS operations. Opportunities to leverage existing power, utilities and process equipment have been included in design through careful brownfield assessment. Supporting this is a cross-functional team rapidly enhancing their hydrocarbon toolkit with the opportunities that CCUS integration presents.

International legal aspects of the construction and operation of the «Baku-Tbilisi-Ceyhan» oil pipeline

The purpose of this article is to analyze the legal acts that make up the legal basis for the construction and operation of the main oil export pipeline "Baku-Tbilisi-Ceyhan", passing through the territory of such states of the region as Azerbaijan, Georgia and Turkey. These legal acts involve two types of agreements. The first type is international treaties that are made between the countries in the region. The second type is host government agreements that are made between the governments of the states and operational partners. The methodological basis of the study is the following theoretical methods of cognition: analysis, synthesis, induction, deduction, analogy, as well as special methods of cognition of legal phenomena and processes: comparative legal and formal legal. The article reveals the main elements of the Agreement between the Republic of Azerbaijan, Georgia and the Republic of Turkey relating to the transportation of petroleum via the territories of the Republic of Azerbaijan, Georgia and the Republic of Turkey through the Baku-Tbilisi-Ceyhan main export pipeline and the Agreement between Kazakhstan and Azerbaijan on supporting and facilitating the transportation of oil from the Republic Kazakhstan through the Caspian Sea and the territory of the Republic of Azerbaijan to international markets through the Baku-Tbilisi-Ceyhan pipeline, which ensured the connection of Kazakhstan to this oil pipeline. According to the author, the applied mechanism for regulating the construction and operation of an international pipeline project by acts of a public law and private law nature is effective, since it allows considering the interests of entities of various statuses interested in the project implementation: states and operational partners (investors).

Subsea pipelines incidents prevention: A case study in Brazil

There are more than 4000 subsea pipelines in Brazil. These pipes include umbilicals, drilling risers, flexible risers, rigid risers, hybrid risers, flowlines, and export pipelines. Despite all standards, regulations, guides, and risk management tools designed to avoid events, subsea pipeline incidents still occur, revealing possible failures in companies' risk control. Identifying similarities between different subsea pipeline failure events is crucial to improving the design, risk management practices, and regulation requirements, besides promoting accident prevention. This paper proposes applying the life cycle and management practices combined to analyze subsea pipeline incidents from the RDI (Detailed Incident Report) and investigations reported to ANP (Brazilian National Agency of Petroleum, Gas, and Biofuels), the Brazilian safety regulatory agency. Furthermore, subsea pipeline incidents data were analyzed: correlated circumstances, consequences, and causes. The results show that most riser and flowlines causal factors are related to equipment failures, and recurrent root causes are design errors and integrity control. Based on the proposed approach, it was possible to identify gaps in most riser and flowlines accident investigations since there are few causal factors, root causes, and the absence of riser and flowlines failure mode and mechanisms. Therefore, the development of accident recommendations can be compromised. Thus, this paper proposes improvements to current Brazilian regulations to clarify the minimal subsea pipeline accident investigation requirements.

Evaluation and Optimization of an Export Gas Compressor in a Natural Gas Project

AbstractThe possibility of removing the export gas compressor from the central process facilities (CPF) in a gas project and enlarging the size of the gas export pipeline from the CPF to reduce the total capital expenditure (CAPEX) and operating expenditure (OPEX) is evaluated. Adding the export gas compressor to the CPF will increase the carbon footprint of the CPF, the power requirements of the CPF, and the emission of greenhouse gases. The CPF equipment would be designed for a lower operating pressure which leads to larger equipment sizes. PIPESIM and HYSYS software were used to simulate the CPF and different sizes of the export gas pipeline. With an export gas pipeline size smaller than 24”, an export gas compressor is required for the CPF, and as the pipeline size is reduced, the compressor power requirement will rise. CAPEX and OPEX comparisons were conducted between adding the export gas compressor or enlarge the size of the export gas pipeline. CAPEX and OPEX decline with larger pipeline size.

Is It Twilight for Deepwater US Gulf Megaprojects?

In early February, TotalEnergies revealed its plans to withdraw from the North Platte deepwater development in the US Gulf of Mexico (GOM). Given the historically inviting and economically competitive US offshore when it comes to oil and gas development, word of the French producer’s decision struck an ominous chord. Things have changed for operators looking to forward multibillion-dollar megaprojects in the GOM. Today, there may be more headwinds than ever before facing future large-scale developments—an unfavorable political regime, competition for investment not only with other oil projects around the world but also with renewable projects, and supply chain woes that have made the waits for long-lead-time items even longer, along with the simple fact that the region has gone several years with very few major discoveries. The backlog of potential GOM megaprojects is stuck in the single digits, and likely is less than five. Shell has its Leopard find and Blacktip complex. Equinor has Monument. After that, things get gray. The number of Lower Tertiary wells—where any elephant fields remaining would likely be found—has decreased steadily over the past decade (Fig. 1). According to the Bureau of Ocean Energy Management (BOEM), six Lower Tertiary exploration wells each were drilled in both 2013 and 2014. That number dipped to four in 2015 and 2016. Only one was tallied each year between 2018 and 2020. Of the 25 Lower Tertiary wildcats drilled between 2013 and 2020, BOEM counts seven as oil discoveries, nine as noncommercial, and nine as dry holes. The slide in activity could be related to soft oil prices or it could be that the region, which has been actively explored since around 2000, has matured. TotalEnergies’ Chief Patrick Pouyanne told investors that it was not US policy that made the company shift gears, but rather the fundamentals of the company’s portfolio. “It’s a purely intrinsic decision linked to the project and linked also to our capital allocation,” he said. “It’s honestly at the limit—at the high limit of the range we gave ourselves. North Platte, because of its size, in fact, we knew it. It’s not a giant field. It’s really on the high side of these metrics. So that’s one point. And second point, we prefer to invest in Sepia and Atapu in Brazil rather than in North Platte.” North Platte straddles four blocks in the Garden Banks area of the US GOM in about 1300 m of water. The field development plan was based on eight, 20,000-psi subsea wells and two subsea drilling bases connected via two production loops to a newbuild, lightweight floating production unit (FPU). Oil production at plateau level was expected to average 75,000 B/D with associated natural gas. “TotalEnergies just signed up with Brazil, which has projects more along the lines of what they’re looking for—200,000 B/D-type projects with future upside,” explained Justin Rostant, principal analyst with Wood Mackenzie. “Similarly, in Uganda, they just signed on the Lake Albert (Tilenga) project, which includes multiple fields they’re going to jointly develop—again another 200,000 or 250,000 B/D project. The Uganda project also includes investments in a 60,000 B/D refinery, a 1440-km export pipeline, and potentially a renewable power project. So, truly it’s an integrated megaproject. They also just had a massive discovery in Namibia. Again, a multibillion-barrel discovery that will turn into another megaproject. Those are the kind of projects they’ve been looking at and North Platte just could not compete.”

Embedment depth and uplift capacity of a cryogenic pipeline dynamically laid in a trench

A cryogenic pipeline is a pipe-in-pipe with larger outer diameter, and is heavier and stiffer, compared to conventional deepwater steel flowlines or export pipelines. Cryogenic pipelines are being considered to be placed on shallow water sandy seabeds for transporting liquefied natural gas to shore. This paper reports a series of centrifuge tests to assess the as-laid embedment of a cryogenic pipeline during the dynamic laying process, and the uplift capacity of a trench-laid pipeline. Two seabed conditions were tested – a pipe laid onto the base of a trench and a flat silica sand deposit. A total of 12 dynamic pipe laying tests were conducted varying vertical force and pipe oscillation amplitude, frequency and number of cycles; encompassing typical laying processes. The embedment depth was found to be less than 0.5 diameters, owing to the resultant effect of lateral ploughing and sand densification. For the trench-laid cases, after the completion of simulating the pipe laying process, the trench was filled with a layer of sand and a layer of rock armour; varying the thickness of the layers. The pipe was then extracted vertically to evaluate the uplift resistance, which was shown to increase with increasing the thickness of the rock layer.

Polityka bezpieczeństwa energetycznego Chińskiej Republiki Ludowej wobec państw kaspijskich Azji Centralnej

In contemporary international relations, the issue of energy security is becoming fundamental. Access to energy resources is an existential need of every country, conditioning its economic and social development. In such a situation, states try to construct long-term energy security policies to ensure smooth supplies of raw materials. The research problem is the analysis of the energy security policy of the People’s Republic of China towards the Caspian states of Central Asia: Kazakhstan and Turkmenistan. In the research process, a hypothesis was verified, assuming that China’s energy security policy in the Caspian region of Central Asia is determined by the increased demand of this superpower for energy resources and geographical proximity to oil and gas deposits located in Turkmenistan and Kazakhstan. The People’s Republic of China (PRC) became interested in the hydrocarbon resources of the Central Asian region right after the collapse of the USSR. At that time, the energy security policy of this superpower was implemented in several stages: from gaining access to the oil and gas reserves of the countries of the region to the construction of export pipelines supplying the absorptive Chinese market. Thus, the analysis presents the conditions of the PRC’s energy security policy, its institutional dimension and actions towards Kazakhstan and Turkmenistan, both in upstream and midstream terms.

Development of KPI’s for Ageing Export Pipelines in the UK North Sea

Abstract: Export pipelines are of inestimable value to the oil and gas industry, as they have continuously provided a path and means for hydrocarbon transportation. The most recent report from the UK HSE shows that there are about 1372 pipelines installed in the UK North-sea and about 442 of them are ageing export pipelines. The most unique function of these pipelines is to convey fluids from HC wells to the available processing facility; which are applicable for both onshore and offshore applications. During the useful life of these pipelines, they encounter various degradations that range from fatigue, corrosion, thermal expansion, spans, erosion and many other associated third-party challenges. It is the responsibility of duty holders to ensure that these degradations do not propagate into triggering hazardous and catastrophic incidents, to this effect, it is necessary for operators to protect the state of these pipelines by the application of an efficient management structure known as Pipeline Integrity Management System (PIMS). Keywords: Pipeline, Export, Ageing, Key Performance Indicators, PARLOC, OGP, Management, Integrity, Degradation Mechanism, Mitigation, PIMS.

Reduced-Order Modeling Framework Enables Dynamic Process Optimization

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202643, “Dynamic Process Optimization Using a Reduced-Order Modeling Framework,” by Ravikishan Guddeti, SPE, IPCOS, and Sathish Sankaran, SPE, Xecta Digital Labs, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The role of process operations upstream, midstream, and downstream is critical to fundamental business resilience and production optimization in a dynamic environment. In the complete paper, the authors propose a fast, hybrid, self-learning dynamic process-modeling method derived from routine plant measurements that can be used for short-term forecasts, scenario modeling, and process optimization and control. Introduction The methodology, reduced-order modeling (ROM), can use large quantities of data from plant sensors to create a dynamic process model that can be used to optimize process performance. The authors propose a model structure and a hybrid method that is physically intuitive and interpretable and can learn incrementally in real time and thus can augment human intelligence with fast machine-derived insights. Problem Description In the offshore facility system considered in this work, the oilwell flowlines are connected to the platform through risers that terminate at the facility inlet. Each topside flowline includes a subsea production flowline connected to a pressure-controlled choke. This topsides flowline choke is used to control production rate or manage slugging conditions. The facility is designed to provide separation and processing of the oil and condensate production as required to meet export pipeline specifications. A typical oil-separation train consists of many stages of separation and contains liquid surge volume to accommodate surges in liquid rate that may occur from wells or subsea flowlines. Depending on the space available, these separators are two- or three-phase separators. The liquid from each stage is dumped to the subsequent stage of separation, allowing the three phases (oil, gas, and water) to separate. Gas from each stage of separation is compressed, treated to remove water, and then pumped into the export line. Water removed in the separation trains is routed to treating systems before being dumped back into the sea. The dry oil is stored in the dry oil tank and pumped out to the pipelines. Each well has different characteristics that change with the age of the well. As the wells mature with reduced reservoir pressures and increased gas/oil ratio, the hydrocarbon phases travel at lower velocity, resulting in unstable flow regimes. When wells producing at high water cuts are brought online, combined with low gas flow rates and low wellhead pressure, the potential for slug flow can disrupt steady operation of the separation train. The frequency of these events increases with aging reservoirs and high-water-cut production. An effective real-time tool is needed that can monitor current operating conditions continuously and is able to run through alternative mitigation strategies quickly using the predictive model to analyze the effect on downstream processes.

Adopting Risk Based Maintenance Strategy of Export Gas Pipeline Using House of Risk: A Proposed Framework

42” SNP-BEM is the biggest buried gas export pipeline belong to PT XYZ and has been operated joinly with PT POMA for duration of 20 years. Until today, this pipe has survived very well from the worst potential failure or risk events such as rupture and leak since all strategic of maintenances are considered as sufficient facing the sources of risk agent, despite still different perceptions are presence among the operators in real application. Nevertheless, following the operation versus times, there is an increasing of potential external threat or risk agents due to the growth of housing, the overlapped operational permit of industrial of non-oil/gas, illegal road crossing which may cause the occurrence of risk events/failures. In 2016, there was a critical incident of the soil movement caused by the excessive load of coal’s stock pile nearby ROW and impacted to the pipe movement about 6 meters in horizontal and 2 meters in vertical and may lead to disastrous. Therefore, a more effective maintenance strategy is to be developed to reduce these risks. Combination of Fish Bone diagram (FBD) and House of Risk (HOR) is selected to identify the sources of risk and to develop more effective risk-based maintenance strategy. Based on the assessment, it is identified (twelve) 12 credible risk agents which contributing to pipeline failures/risk events and (eight) 8 proposed preventive actions to reduce the risk. These proposed actions shall be agreed by all operators as a reference for developing risk-based maintenance strategy.

Definition and analysis of overall heat-transfer coefficient at the sections of “hot” export petroleum pipeline operating in northern winter conditions

Background. Receiving information on overall heat-transfer coefficient of pipeline pumping down the heat oil is required for resolving a number of process challenges: definition of specific cooling-off intensity of delivered petroleum, optimization of delivery processes, insulation efficiency assessment of pipeline sections etc. Aim. The actual values of the heat transfer coefficients are the most reliable basis for the implementation of optimization and technological calculations during thermohydraulic modeling and development of measures (a) to save energy during hot pumping and (b) to increase the reliability of the “hot” pipeline in order to exclude the possibility of its self-stopping and “freezing”. In the context of assessing the technological reliability of pumping, the determination and analysis of the total heat transfer coefficient for the sections of the oil pipeline were carried out and the capabilities of this methodological approach were demonstrated. Materials and methods. In the article, by the example of 266-kilometer long export pipeline (Ø 300 mm), functioning in «hot» delivery mode is presented the calculation process of defining the actual values of overall heat-transfer coefficient in route sections, and is done the analysis of this coefficient values, operation heating mode of the pipeline and their related factors of technological reliability of oil delivery process. Results. The difference in the values of the overall heat transfer coefficient at the sections of the pipeline is shown, which allows us to come to a practical conclusion about the different intensities of the thermal processes occurring in its different linear sections (aboveground, underground with intersection of marshy soils and rivers, with and without thermal insulation, operating in non-isothermal and isothermal modes). Conclusions. The proposed approach to determining the actual values of the total heat transfer coefficient for sections of the “hot” oil pipeline in combination with the analysis of the data obtained provides opportunities that are largely in demand from a methodological point of view and extremely important from a practical standpoint.

Debates about export pipelines from the post-Soviet region: Opinion leaders and advocacy coalitions

Based on a content analysis of over 5,500 media articles, this contribution analyses debates about export pipelines in five post-Soviet countries, namely Azerbaijan, Kazakhstan, Russia, Turkmenistan and Ukraine, focusing on time periods of decisive pipeline decisions. The analysis covers the entirety of the policy communities engaging in these debates, identifying opinion leaders, dissenting voices and relevant cleavages. It shows that even in authoritarian regimes broad groups of actors are involved in pipeline debates, with not just the ruling elites, but also representatives of foreign states and companies as well as domestic and foreign experts playing prominent roles. In most cases, a broad consensus about pipeline choices seems to be genuine and not the result of political pressure. This consensus focuses on narrow considerations of direct commercial and political gains from pipeline projects, largely ignoring broader societal and environmental impacts.

Early Production Life of Wheatstone Project Offshore Australia Yields Key Lessons

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202246, “Wheatstone: What We Have Learned in Early Production Life,” by John Pescod, SPE, Paul Connell, SPE, and Zhi Xia, Chevron, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Asset Overview Chevron Australia’s Wheatstone project is in the North West Shelf region offshore Australia (Fig. 1). Two gas fields, Wheatstone and Iago (along with a field operated by a different company), currently tie into the WP in the Northern Carnarvon Basin. These two gas fields are in water depths between 150 and 400 m. The platform processes gas and condensate through dehydration and compression facilities before export by a 220-km, 44-in., trunkline to two 4.45-million-tonnes/year LNG trains and a 200 tera-joule/day domestic gas plant. A Wheatstone/Iago subsea system consisting of two main corridors delivers production from north and south of the Wheatstone and Iago fields to the WP. Currently, the subsea system consists of nine subsea foundation development wells, three subsea production manifolds, two subsea 24-in. production flowlines, and two subsea 14-in. utility lines. The nine foundation development wells feed the subsea manifolds at rates of up to 250 MMscf/D. These wells have openhole gravel-pack completions for active sand control and permanent downhole gauges situated approximately 1000-m true vertical depth above the top porosity of multi-Darcy reservoir intervals for pressure and temperature monitoring. All wells deviate between 45 and 60° through the reservoir with stepout lengths of up to 2.5 km. The two subsea 24-in. production flowlines carry production fluids from the subsea manifolds to two separation trains on the WP. Each platform inlet production separator can handle up to 800 MMscf/D. The two 14-in. utility flowlines installed to the subsea manifolds allow routing of a single well to the platform multiuse header, which can direct flow into the multiuse separator (MUS) or other production separators at a rate of 250 MMscf/D.

E&P Notes (September 2020)

Petrobras Slices Time, Cost of Post-Salt Drilling Lynnmarie P. Flowers, Technology Editor Petrobras has cut in half the time and cost of drilling some wells using its patented True One Trip Ultra Slender (TOTUS) concept. The technique can be used in certain mature fields of the postsalt where geological and reservoir characteristics favor its application. With TOTUS, the firm drilled a well in 44 days in early July, compared to the historic average of 96 days, resulting in a cost reduction of approximately 50% or $30 million. The development of post-salt wells offshore Brazil has been a challenging project. Faced with water depths of 2000-plus m - and a salt layer 2000 m thick - to reach reservoirs at 7000 m below sea level, Petrobras had the need to use novel technological and procedural techniques. Canada’s Oil Production Sinks to 2016 Levels In the first half of 2020, Canada’s production declined 20% from its 2019 average of 5.5 million B/D as a result of low crude oil prices, reduced demand, and continued production curtailments imposed by the government of Alberta. Last year, when Canada was the world’s fourth-largest producer, the province accounted for more than 80% of its production. Canada produced about the same amount of petroleum and other liquids in 2019 as it did in 2018, when western Canadian select crude oil was trading at historically low prices. The government of Alberta imposed production curtailments in early 2019 to reduce associated bitumen production and reduce inventories and growing constraints on export pipeline capacity. These restrictions were extended through the end of this year. MOL Pakistan Discovers Gas and Condensate As the operator of the TAL Block in Pakistan, MOL has made a new gas and condensate discovery at the Mamikhel South-1 exploratory well. This marks the company’s thirteenth discovery in Pakistan, its tenth in the TAL Block, and the second time in 3 months to discover hydrocarbon reserves. In March, MOL Norge discovered oil and gas in the North Sea. MOL has made 13 oil, gas, and condensate discoveries in Pakistan since 2000 including over 400 million BOE hydrocarbon reserves. It is responsible for 89 million BOED gross production (as of Q1 2020) in the TAL Block, where it has an 8.4% share. DTEK To Conduct Large-Scale Green Seismic Exploration DTEK Oil & Gas this year will conduct a large-scale seismic survey using green technology on a gas-and-condensate field in Ukraine. The recording of seismic data in real time will allow DTEK to assess the quality of data logged during execution, increasing the quality of geophysical information recorded during the course of work. The cordless “green seismic” technology is connected via wireless systems in lieu of cables, enabling the exploration of complex and previously inaccessible landscapes, shortening project-completion time, and reducing environmental impact. The technology does not require special heavy machinery for installation. Supreme Court Ruling on Oklahoma Tribal Land Raises Questions for Oil Industry A US Supreme Court decision recognizing about half of Oklahoma as Native American reservation land has implications for oil and gas development and raises regulatory and tax questions that could take years to settle. On 9 July, the court overturned an Oklahoma tribe member’s criminal conviction - in the McGirt v. Oklahoma decision - because the crime was com-mitted on reservation land and therefore outside the reach of state criminal law. CNOOC Starts Production From Luda Project Exploration and production independent CNOOC has produced first oil from its Luda 21-2/16-3 regional development in the Bohai Sea, offshore China. The project currently contains one central platform, three wellhead platforms, and one production platform. CNOOC expects to drill 69 development wells; peak production is expected to reach 25,600 B/D in 2022. Situated about 25 miles north of the Luda 10-1 oil field and 55 miles northwest of the Suizhong 36-1 onshore terminal, the Liaodong Bay development is operating in an average water depth of 82 ft. Cairn Sells Senegal Interest to Lukoil Russia’s Lukoil will sell its entire 40% interest in the Rufisque, Sangomar, and Sangomar Deep (RSSD) contract area to Edinburgh oil and gas producer Cairn Energy for up to $400 million. Lukoil intends to return at least $250 million to shareholders as a special dividend after the sale. The blocks of the project covering 2212 km2 are located on the deepwater shelf of the Republic of Senegal 80 km from the shore with the sea depth of 800-2175 m. The blocks include two discovered fields, Sangomar and FAN. The cash consideration payable on completion is $300 million, and up to $100 million depending on the timing of first oil and the average Brent oil price in the first 6 months of production.