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BP has entered a contract with Sempra Energy and Mexico's Infraestructura Energetica Nova for delivery of the company's first carbon-offset liquefied natural gas cargo. The cargo was delivered on 16 July to the Energia Costa Azul terminal, a joint venture between Sempra and IEnova, in Mexico's Baja California. The cargo will be sourced from BP's global LNG portfolio, and its estimated emissions will be offset using carbon credits sourced from a BP forest creation project in Mexico. "We are excited to advance our goal to lower GHG [greenhouse-gas] emission intensity at our LNG facilities," said Justin Bird, chief executive of Sempra LNG. "Sempra LNG continues to build a strong business portfolio focused on sustainability and the global energy transition."
Russian oil major Lukoil agreed to acquire the 50% operator interest held by Houston-based Fieldwood Energy in Mexico's Area 4 offshore shallow-water project for $435 million plus 2021 expenditures incurred up to the closing date of the transaction, Lukoil announced. Fieldwood Energy and PetroBAL, the oil and gas subsidiary of Mexican conglomerate Grupo Bal Sa De CV, won rights in October 2015 to develop Block 4 under a production sharing agreement (PSA). The partners' lone bid in Mexico's second licensing round granted 74% of the pretax profit to the Mexican government but without any increases to the minimum local work program requirements. In August 2020, Fieldwood filed for Chapter 11 bankruptcy protection and in June won approval of its plan to restructure $1.8 billion of debt and invest an estimated $7 billion in environmental cleanup, according to Bloomberg. The Chapter 11 plan was approved in late June after 5 days of virtual testimony and argument in the US Bankruptcy Court for the Southern District of Texas which highlighted such issues as the legal ins and outs of plugging oil wells that are no longer in use, Bloomberg reported.
A ruling by Mexico's Energy Secretariat, or SENER, this month has made the national oil company Pemex the operator of the contested Zama field that was discovered by Houston-based Talos Energy in 2017. The companies have been in dispute over the shallow-water Zama prospect since 2018 after Pemex claimed that the discovery was a contiguous reservoir that extends into its offshore block. Independent reserves audits commissioned by each company have supported their own claims, with Talos' audit showing that 60% of the reservoir's estimated 670 million BOE fell within its block. Pemex estimates that its block represents 50.4% of the Zama reservoir. In statement issued 5 July, Talos lamented the decision and highlighted that it has drilled four wells in the Zama field (one exploratory, three delineation wells) and has demonstrated to Mexican authorities its ability to operate the unit.
Pemex, Mexico's state-owned oil company, said a 2 July leak in the 12-in. There was no oil spill, and immediate actions taken to control the fire on the surface prevented environmental damage, the operator said. The platform is part of the large Ku-Maloob-Zaap field cluster, which is among the company's most profitable producing assets. "As a result of these events, and after approximately 5 hours, the fire was extinguished in its entirety by closing the underwater valve and injecting nitrogen into the pipeline," Pemex said in a statement. Bad weather with heavy rain appears to have set off the chain of events that led to the fire, including the pneumatic pumping gas turbocharging equipment necessary to produce the wells being knocked out of operation.
LLOG Exploration has started production from the Praline field in Mississippi Canyon Block 74 of the US Gulf of Mexico. The Praline subsalt well was drilled in 2,600 ft of water to a total depth of 13,400 ft and encountered over 125 ft of net Pliocene-aged hydrocarbons. The well was originally drilled in the spring of 2017 but was completed in August 2020 and has been tied back to the Talos Energy-operated Pompano platform in nearby Viosca Knoll Block 989 in 1,290 ft of water. LLOG operates Praline with a 27.25% working interest. Partners in the field are entities managed by Ridgewood Energy, including ILX Holdings, Red Willow Offshore, Houston Energy, and CL&F Offshore.
BHP awarded McDermott International a contract to provide a marine installation campaign for the Shenzi subsea multiphase pumping project in the deepwater US Gulf. The Shenzi development comprises approximately 15 subsea wells located across Green Canyon blocks 609, 610, 653, and 654, tied back to a tension-leg platform (TLP) hub in a water depth of 4,400 ft. The scope of the contract includes project management; detailed design and fabrication for a pump station suction pile; umbilical installation and flexible jumpers and flying leads installation; transport of all materials and equipment; and precommissioning services and other necessary testing and surveys. The $150-million subsea pumping project will allow for increased recovery from existing wells, with the operator anticipating an additional 4,000 B/D. "McDermott's North Ocean 102 vessel is uniquely qualified to transport and install the materials and equipment for the Shenzi project scope--as well as perform precommissioning testing and other necessary surveys to safely deliver for the customer," said Mark Coscio, senior vice president for McDermott's North, Central and South America region.
Submersibles have application in a limited number situations. There are only seven submersibles left in existence, all located in the Gulf of Mexico. The water depth range for submersibles is between 9 and 85 ft, with a lesser depth rating during hurricane season. Despite their narrow water depth range, they still serve an important, although limited, segment of the market. Most jackup rigs cannot operate in less than 18 to 25 ft of water, although a very few can move into as little as 14 ft. of water.
Abstract The success or failure of cement plugs are known to alter the timeline of an oil well; not to mention the additional costs and NPT associated with the rig activities. Unsuccessful cement plug costs oil companies considerable amount of capital both in extra rig time and service company expenses. Suggested procedures for placing cement plugs have been presented in number of papers - comprising of slurry design, spacer recommendations, laboratory testing and placement techniques. However, it is very easy to deviate from these standard practices due to over confidence, negligence or both. In Mexico, it was observed that the success rate of placing cement plugs dropped due to operational and engineering design shortcomings. Towards the end of 2018 there were several unsuccessful cement plug jobs that questioned the regular plug procedures. Careful analysis of the past mistakes led to the conclusion that an effective approach to alter the local plug placement practices was necessary. An updated cement plug placement software was used in conjunction with strict standard practices that turned around the trend and enabled consistent successful placement of cement plugs in the first attempt itself. A detailed yet simple approach towards cement plugs was adopted in both engineering design and operational execution. Additionally the updated plug placement software ensured accurate prediction of the cement plug top; that was confirmed by the actual tag of the plug. This paper will enlist the major analysis carried out on the unsuccessful plug jobs and highlight the different techniques that were adopted in the subsequent jobs to ensure successful placement and tagging of the cement plug. The paper will also focus on how the plug placement software's new additional features have made a significant contribution to this success story.
Oliveira, Jansen (REPSOL) | H., Karl Perez (REPSOL) | V., Alejandro Martin (REPSOL) | T., Ricard Fernandez (REPSOL) | N., Teresa Polo (REPSOL) | V., Lorenzo Villalobos (REPSOL) | Dubost, Francois Xavier (Schlumberger) | V., Manuel Lavin (Schlumberger) | Gisolf, Adriaan G. (Schlumberger) | Jackson, Richard R. (Schlumberger) | Edmundson, Simon (Schlumberger) | Dumont, Hadrien (Schlumberger) | E., Hugo Hernandez (Schlumberger) | Espinosa, Javier (Schlumberger)
Abstract Offshore exploration requires the evaluation of hydrocarbon presence, estimation of volumes in place, and flow potential. To this capacity, formation testers are widely used to determine static data such as reservoir fluid gradients and reservoir pressure, obtain fluid samples, and to assess reservoir connectivity. Dynamic data, acquired with interval pressure transient testing and well testing techniques, are used to assess reserves and productivity. However, these evaluation techniques provide dynamic data at different resolution and length scales, and with different environmental footprint, cost, and operational constraints. A new wireline formation testing technique known as deep transient testing (DTT) has been introduced, which combines high-resolution measurements, higher flow rates, and longer test durations to perform transient tests in higher permeability, thicker formation, and at greater depth of investigation than with previous formation testers - without flaring and at a low carbon footprint. The platform combines advanced metrology with extensive automation to generate unique, real-time reservoir insights. Traditionally, pressure transient analysis and well deliverability predictions were produced through an analytical framework. Today, deep transient testing measurements are interpreted, and placed in reservoir context, in real-time by integration with geological and reservoir models. These steps can be performed from any wellsite utilizing cloud-based resources. Products such as reservoir fluid compressibility, saturation pressure, equation of state (EOS) models, well productivity, or minimum connected volumes are integrated in real-time interpretation utilizing numerical analysis. The digital infrastructure enables key reservoir insights to be shared between all stakeholders in a transparent and collaborative environment for both operational control and rapid decision making. This paper presents a case study where the new DTT technique was combined with numerical analysis and real-time integrated workflows to characterize a multilayer reservoir in a recent discovery in deepwater Mexico. During the drawdown phase of the DTT operation, real-time downhole fluid analysis was used to determine the fluid composition, density, viscosity, compressibility, and saturation pressure. These fluid properties were then used to generate and tune an EOS model. Accurate drawdown flow rate measurements and the subsequent pressure transients were combined with the fluid model and geologic model to enable integrated pressure transient history matching. The resulting calibrated numerical model honors the fluid measurements and geologic model and was used to predict the permeability profile, zonal producibility, and the volume of influence of the test.