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There are different definitions of what is Well Integrity. The most widely accepted definition is given by NORSOK D-010: "Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well." Other accepted definition is given by ISO TS 16530-2 "Containment and the prevention of the escape of fluids (i.e. Well Integrity is a multidisciplinary approach. Therefore, well integrity engineers need to interact constantly with different disciplines to assess the status of well barriers and well barrier envelopes at all times. Wells that are used for steam injection or steam soak production or Geothermal heat are subject to high differences in thermal cycling and also referred to as Thermal wells.
Sinopec announced this week that production at China's largest shale-gas development has jumped 20% year-over-year. This is based on first quarter results that showed natural-gas production from the Fuling gas field in Chongqing reached a cumulative output of 1.78 Bcm, or nearly 63 Bcf. The boost comes after Sinopec brought 28 new wells on stream this year, the state-owned oil and gas producer said in an announcement. Sinopec is China's second-largest gas producer and said during its earnings call that it is aiming for an annual increase in gas output of 10% over the next 3 years. The operator produced a total of 30.2 Bcm in 2020 and is aiming for 34 Bcm this year. Sinopec's next expected milestones are 38 Bcm in 2022 and 42 Bcm in 2023.
Hess Corporation announced today it is selling about 78,700 acres of its Bakken Shale position to Enerplus Corporation for $321 million. Oil production from the areas that are part of the deal averaged around 4,500 B/D over the first quarter of the year, Hess said in a statement. Calling the Bakken Shale a "core asset" for the company, CEO John Hess said the majority of the assets being sold off were not going to be drilled on until 2026 which "brings material value forward and further strengthens our cash and liquidity position." Enerplus considers much of the acreage to be Tier 1 and estimates it adds 2 or 3 years to its Bakken development runway, giving it an estimated 10 years' worth of drilling locations in the region. At current oil prices, Enerplus said the Tier 1 acreage and other areas amount to 120 undrilled locations.
MODEC may elect to appeal a decision laid down by Brazilian state oil company Petrobras that makes the contractor ineligible to bid on new work tenders for 13 months. The contractor received notification from Petrobras of the suspension, which cited the main basis for the sanction being losses to Petrobras caused by the performance of a trio of FPSOs under charter services that MODEC provided in the past or is presently providing the operator. The suspension period began 31 March 2021. The FPSOs are the FPSO Cidade do Rio de Janeiro MV14, whose charter contract expired in 2019, and two FPSOs which are currently chartered to Petrobras, the FPSO Cidade de Niterói MV18 and the FPSO Cidade de Santos MV20, according to the notification. In 2019, MODEC found cracks at the hull of the FPSO Cidade do Rio de Janeiro MV14 while the unit was on location for Petrobras at the Espadarte field in the Campos Basin.
Southeast Asian operators sit in the middle of the world's fastest growing economic region where energy demand is expected to double over the next 20 years. But this picture of growth has been juxtaposed with the region's declining oil and gas production--most of which comes from offshore fields--that has left it increasingly reliant on imports from overseas suppliers. The degree to which operators in Malaysia and Indonesia can help counter this trend was the focus of an executive panel last week at the International Petroleum Technology Conference (IPTC). While acknowledging that the region is marked by challenging geologies and mature offshore fields, the executives spoke highly of what the future holds. Several things underpin their optimism, not least of which is the region's rising demand for natural gas.
Subsurface woes that have plagued Petronas' Yetagun development since the beginning of the year have prompted the Malaysian state-run oil company to declare force majeure and temporarily cease production from the field. Yetagun is in the Andaman Sea, offshore Myanmar, in Blocks M12, M13, and M14. According to Petronas subsidiary PC Myanmar Ltd. (PCML), following challenges in well deliverability, gas production fell below the technical threshold of the offshore gas processing plant. The operator did not give a timetable for the return of production from Yetagun, adding only that it will be halted until further notice. "There has been a drastic decline in production level due to subsurface challenges in the field since January 2021 and it has further deteriorated recently," said PCML country head Liau Min Hoe.
Qatar Petroleum (QP) revealed this week that from 1 January 2022 it will take over 100% ownership of Qatargas Liquefied Natural Gas Company Ltd. (QG1) following a decision not to renew the joint venture agreements that expire on 31 December 2021. QG1 was established in 1984 and comprises the first three LNG trains in Al Khawr, Qatar. The project has an annual capacity of 10 million tonnes of LNG. It is a joint venture between QP, which holds a 65% stake, and current partners Total (10%), ExxonMobil (10%), Marubeni Corp (7.5%), and Mitsui & Co Ltd. (7.5%). QG1 was the pioneering LNG project to be developed in Qatar, whose success has paved the way for the development of Qatar's LNG industry, which is targeting production of 126 mtpa by 2027 via new production from the planned North Field expansion project.
Pioneer Natural Resources announced late Thursday an agreement to acquire smaller oil and gas producer DoublePoint Energy in a deal valued at $6.4 billion, including $900,000 in debt and liabilities. The transaction gives Pioneer an additional 95,000 acres of leases in Midland Basin, the eastern half of the Permian Basin that lies entirely within Texas. Pioneer will boast more than 1 million net acres in the Permian after the deal closes, which is expected to happen next quarter, and has emphasized that its positions are not on federal lands where new leasing has been paused indefinitely by the White House. In exchange, DoublePoint shareholders will receive more than 27 million shares of Pioneer and $1 billion in cash. The stock portion of the deal will effectively give DoublePoint shareholders 11% ownership of Pioneer which is expected to have a pro-forma market value near $47 billion.
Kozlowski, Maciej (Halliburton) | Chakraborty, Diptaroop (Halliburton) | Jambunathan, Venkat (Halliburton) | Lowrey, Peyton (Halliburton) | Balliet, Ron (Halliburton) | Engelman, Bob (Halliburton) | Ånensen, Katrine Ropstad (Aker BP) | Kotwicki, Artur (Aker BP) | Johansen, Yngve Bolstad (Aker BP)
The Alvheim Field in the Norwegian North Sea was discovered in 1998. Two wells were drilled in 2018 in the Gekko structure to confirm oil column height and to evaluate reservoir quality in the Heimdal Formation. A comprehensive wireline logging program, including NMR and formation testing, was optimized to reduce formation evaluation uncertainty. Evaluating fluid properties, oil column height, and reservoir quality were primary objectives. Well A was first drilled on the south of the structure, followed by Well B on the north of the structure. Reservoir quality encountered in both wells was very good, and a project to develop these resources is currently in the selection phase. Formation evaluation uncertainty encompassing pore geometry distribution, permeability, reservoir quality, and hydrocarbon identification are mitigated by studying the nuclear magnetic resonance (NMR) log response. NMR fluid typing has been widely used in the oil industry since the 1990s. NMR fluid typing today is a combination of the contrast of spin relaxation time T1, the spin-spin relaxation time T2 (T1T2), and the diffusivity (T2D) of formation fluids (Chen et al., 2016). NMR fluid typing can be obtained from a continuous log and/or stationary log measurements. This paper showcases excellent, textbook-quality NMR data, as well as the integration of NMR data in the petrophysical workflow. High-confidence fluid properties and fluid contacts are determined. This paper also highlights a comparison of NMR data acquired in stationary vs. continuous depth-based log modes in both wells. The continuous log data quality is equivalent to stationary data, implying continuous log data quality is sufficient for reliable NMR fluid properties evaluation without depending on time-consuming stationary NMR measurements. Reducing logging operations rig time is very advantageous in the North Sea, where drilling rig operations cost is high, and enhanced rig time management is constantly required.
Gianotten, Ingrid P. (Lundin Energy Norway AS) | Rameil, Niels (Lundin Energy Norway AS) | Foyn, Sven E. (Lundin Energy Norway AS) | Kollien, Terje (Lundin Energy Norway AS) | Marre, Julio R. (Miramar Julio Marre) | Looyestijn, Wim (PanTerra Geoconsultants B.V.) | Zhang, Xiangmin (PanTerra Geoconsultants B.V.) | Hebing, Albert (PanTerra Geoconsultants B.V.)
The main Petrophysical challenges in carbonate reservoirs are often to define meaningful rock types, then to establish robust permeability and saturation models for these rock types, as well as to develop a realistic estimation of irreducible water saturation (Swirr). Realistic Swirr estimation is important for predicting production behavior (expected development of water cut) and thus ultimately for planning the future development scheme of a discovery. In this study, we present the 2014 Alta discovery, located in the southwestern Barents Sea. More than 50% of the expected hydrocarbon resources reside within complex carbonate reservoirs of Permo-Carboniferous age that display highly variable rock properties. The initial screening revealed that primary rock textures and pore geometries were, for a large part, overprinted by diagenetic processes. Hence, better control on the reservoir’s diagenetic evolution will be needed to apply a full-scale rock typing workflow. In the meantime, it was decided to proceed with a simplified reservoir characterization approach based on the main stratigraphic building blocks. Sufficient core coverage allowed for using permeability measurements on core samples as direct input to a 3D reservoir model. A customized core analysis program, using whole-core samples, was designed to characterize the effect of large-scale vuggy pores. For modeling water saturation, a workflow based on the Thomeer hyperbola was developed that describes mercury injection capillary pressure (MICP) curves. The results adequately specify the saturation in all the stratigraphic building blocks. However, saturation uncertainty in the reservoir is high due to a highly variable cementation factor (m), unknown wettability, and the presence of residual oil below the current free-water level (FWL). The Alta structure has been and still is leaking gas, causing the FWL to rise over time. To address the otherwise underestimated volumes in the transition zone above the current FWL, a deeper pseudo-FWL was created and used as input to the saturation height function. Despite log-based water saturation (Archie) and core measurements (Dean-Stark) indicating more than 80% water saturation for less permeable reservoir rocks within the oil leg, production tests did not produce water at normal rates. This clearly demonstrated the need to distinguish “nonproductive” pore systems (with capillary-bound fluids; in this case, water) from pore systems contributing to production (“free” fluids). A large MICP data set confirmed that most reservoir rocks exhibit a mix of different pore types and pore-throat diameters. To model this accurately, porosity partitioning in nonproductive microporosity and movable porosity using the NMR logs was performed. Calibrating appropriate T2 cutoffs by matching core MICP to NMR logs in these heterogeneous rocks is seriously hampered by the large difference in sample size. Applying both MICP and NMR measurements to a subset of core plugs helped to resolve this challenge. Comparing the corresponding movable (“free”) porosity to total porosity revealed near-linear relationships for different reservoir rocks. For irreducible water saturation (Swirr), Swimmobile is calculated using the NMR-based movable porosity. Swimmobile is considered to be a close approximation of Swirr. The resulting full-field simulation showed a significantly improved match between model output and recorded well test data.