ADNOC has embarked on the second phase of its ambitious integrated capacity model (ICM) project with the overall aim to optimise its fluid production portfolio from the well level to the processing facilities. A key feature of the new software tool is the ability to track and predict fluid properties over time across the entire production network, comprising thousands of wells and a myriad of pipelines.
The reservoir fluid composition is assigned at well level for each producing reservoir. The compositional tracking over time is straightforward for many wells, but complicating factors do arise, such as
Lateral compositional variation related to complex reservoir charging history Vertical compositional gradients, especially for near-critical fluids The presence of initial and secondary gas caps, resulting in gas coning Injection of miscible gas for enhanced oil recovery
Lateral compositional variation related to complex reservoir charging history
Vertical compositional gradients, especially for near-critical fluids
The presence of initial and secondary gas caps, resulting in gas coning
Injection of miscible gas for enhanced oil recovery
The fluid systems range from medium-API oil to gas condensates and the key chemical components vary as follows: C1 [5-80%], CO2 [0.5-8%], and H2S [0-35%].
Mixing of pressurized fluids with different compositions at various junctions in the network requires a robust thermodynamics model to capture the associated variation in fluid properties, particularly density and viscosity as a function of pressure and temperature. We demonstrate that it is possible to constrain one unified equation of state applicable to all fluids, as long as the fluid systems used for the tuning span the entire range of compositions observed. Mixing of fluid streams is computationally much simpler if each stream is made up of the same components (although in different amounts) with the same component properties. On average, the predicted fluid density is within 1% of the measured value from a multi-stage separator test.
Asia Pacific Santos discovered gas with the Corvus-2 well in the Carnarvon Basin, offshore Western Australia. The well, located in permit WA-45-R, in which Santos has a 100% interest, reached a total depth of 3998 m. It intersected a gross interval of 638 m, one of the largest columns discovered across the North West Shelf. Wireline logging to date has confirmed 245 m of net hydrocarbon pay across the target reservoirs. Total SA and partners ExxonMobil and Oil Search have signed a gas agreement with the government of Papua New Guinea that defines the fiscal framework for the Papua LNG project in the country's Eastern Highlands. The plan involves construction of three 2.7-mtpa LNG trains on the existing PNG-LNG plant site at Caution Bay just west of Port Moresby. Total has 31.1% interest, ExxonMobil has 28.3% interest, and Oil Search has 17.7%.
Africa (Sub-Sahara) Eni discovered up to 250 million bbl of light oil in the Ndungu exploration prospect in Block 15/06 offshore Angola. A well in 1076 m of water reached TD of 4050 m and proved a single oil column of approximately 65 m with 45 m of net pay of 35 API oil. Well results indicate production capacity in excess of 10,000 B/D. Eni operates Block 15/06 with 36.8421% Joint venture partners are Sonangol P&P (36.8421%) and SSI Fifteen (26.3158%). Eni discovered gas and condensate on the Akoma prospect in CTP-Block 4 offshore Ghana. The Akoma-1X exploration well was drilled in 350 m of water approximately 50 km offshore and 12 km northwest of the FPSO John Agyekum Kufuor.
Africa (Sub-Sahara) Oranto Petroleum has signed two production-sharing agreements (PSAs) with Uganda for oil and gas exploration around Lake Albert, the Nigerian company said. The deal covers the Ngassa Shallow and Ngassa Deep plays in blocks near the southern part of Lake Albert, according to the Uganda Ministry of Energy and Mineral Development. The pacts closely followed the signing of a PSA by Australia's Armour Energy that covers the Kanywataba block, a 133-square-mile area that was relinquished by three international companies in 2012 after failed exploration attempts. The agreements with Oranto and Armour involve acreage that was offered in Uganda's first competitive exploration licensing round last year. Uganda discovered oil in 2006 in the Albertine rift basin along the Democratic Republic of Congo border.
We present a novel framework for generating reduced-order models that combines agglomeration of cells from existing high-fidelity reservoir models and flow-based upscaling. The framework employs a hierarchical grid-coarsening strategy that enables accurate preservation of geological structures from the underlying model. One can also use flow information to distinguish regions of high or low flow, and use this division, or other geological or user-defined quantities, to select and adapt the model resolution differently throughout the reservoir. Altogether, the framework provides a wide variety of coarsening strategies that allow the user to adapt the reduced model to important geology and explore and identify the features that most impact flow patterns and well communication. By preserving these features, while aggressively coarsening others, the user can develop reduced models that closely match an underlying high-fidelity model. Various types of simple flow diagnostics based on time-of-flight and volumetric well communication are used to predict the accuracy of the resulting reduced models.
In this paper, we systematically apply this framework to the Great White Field, but also present results from other real or synthetic models, to demonstrate the asymptotic scaling of accuracy metrics with coarsening levels. Our aim is to identify and illustrate best practices when designing and improving coarsening strategies that can guide future applications of the framework to other reservoir models. We also discuss practical limitations when applying the framework to new simulation models where flow regimes or geologic features may differ.
Drilling interbedded formations can induce torsional vibrations that result in inefficient drilling and damage to drillstring components. A common bit choice for these applications is a standard polycrystalline diamond compact (PDC) drill bit; however, PDC bits due to its shearing action often exhibit some level of torsional dysfunction.
Historically, the most effective method to mitigate torsional vibrations in PDC bits is to use fixed depth-of-cut (DOC) control technology that restricts the PDC bit formation engagement at a pre-determined ratio of rate of penetration (ROP) and drillstring RPM. The challenge with using fixed DOC control is finding a compromise between limiting vibrations through targeted sections without limiting ROP in others. To address this, a self-adaptive DOC technology was developed. The self-adaptive DOC technology automatically adjusts the DOC engagement threshold as drilling conditions change, eliminating manual parameter adjustment required at surface to manage torsional dysfunctions.
This paper will cover self-adaptive bit runs from deepwater Gulf of Mexico wells. In a recent run, a 12¼-in. bit drilled past 30,000ft measured depth (MD) in an abrasive and interbedded section. The self-adaptive bit delivered a 48-percent improvement in ROP over the best offset, saving 23 drilling hours while exhibiting 97-percent smooth drilling concerning stick-slip and 100-percent smooth drilling to axial and lateral vibrations. Another application yielded excellent results in a section featuring bottom-hole coring work. In three separate runs, the self-adaptive bit drilled a sand/shale formation with 98-percent smooth drilling concerning lateral vibrations, axial vibrations, and whirl. It also exhibited 97-percent smooth drilling concerning stick-slip. The self-adjusting technology helped to return to drilling despite the coring disrupting the bottom-hole pattern.
Real-time drilling dynamics data measured downhole is used for demonstrating the effectiveness of self-adaptive DOC control technology for sustained drilling performance improvement in deepwater wells.
Byrne, Devin (Schlumberger) | Gurses, Sule (Schlumberger) | Orzechowski, Diana (Schlumberger) | Puccini, Piero (Shell International Exploration and Production, Inc.) | Klein, Mark (Shell International Exploration and Production, Inc.)
The first permanent electrical distributed temperature array system (EDTA-S) was installed with a single trip in water injection wells in the Perdido fold belt, Gulf of Mexico. The oil field is offshore in the Alaminos Canyon block ultradeepwater environment, which consists of heavily faulted sand formations. Water injection is part of field development, and the risk of out-of-zone injection (OOZI) has a negative impact on the pressure support in the oil zone and causes part of the injected water to be allocated to an undesired formation and reducing hydrocarbon recovery.
The EDTA-S was identified as a technology solution to monitor OOZI. It comprises a permanent array of high-resolution temperature sensors distributed across the formation and overlying caprock with discrete dual-sensor pressure and temperature (PT) gauge measurements. A subsea acquisition card interfaces with the subsea control module, sending power and telemetry to the system via an electric cable installed across the completion. The sensors are installed below the feedthrough packer and positioned on a shroud offset from the tubing to thermally decouple the sensors from the tubing and enable monitoring of the formations. The installation is supported with a data interpretation platform that the operator’s technical teams review to assess whether injected water has been rerouted from the reservoir to some other sink, such as a fractured caprock. This ensures that production is maximized by establishing all the injected volume in the reservoir zone.
The first operator to deploy the permanent EDTA-S subsea used it in one water injector in 2016, and one in 2017. To deploy the array system in a single-trip completion, several enabling components were developed and qualified, including an electrical feedthrough system for the tree/hanger, subsea and topside control integration, shrouded tubing for the array sensors, and a feedthrough control line set packer. The completion operations went according to plan, and the sensors were positioned to monitor 100 m of formation above the perforations. The monitoring system was successfully integrated with the subsea controls and topside system and provides real-time monitoring of the injection and warmback periods. A biweekly system data health check shows good quality of data. Warmback data analysis indicates cooling in the nonperforated sand formation and possible water invasion is moving upward. To date, there is no evidence of OOZI into the caprock or channeling to the wellbore. Advanced thermal modeling software was used for interpretation, and a good match has been obtained with sensor measurements. Modeling of warmbacks confirms the data analysis result with no evidence of OOZI currently in caprock. However, continuous monitoring provides value in that it will capture any behavior changes over time.
The paper details the integration of components, execution, and data interpretation of EDTA-S in the Perdido fold belt. There is a significant potential for implementation of this system in deepwater developments to increase recovery factors.
Reverse time migration (RTM) is a very expensive depth imaging algorithm, particularly at high frequencies. The cost of RTM scales to the 4th power of the relative frequency. As such, the increase of the bandwidth for RTM may result in prohibitive costs, also reducing the ability to handle accurately the elastic properties, or to gather output such as surface offset gathers. Herein, we propose a novel method to efficiently cut the cost of RTM without sacrificing image quality, hence enabling the use of most advanced features in production environment. This new approach involves using a depth-variant migration strategy, with spectrum balancing.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 207A (Anaheim Convention Center)
Presentation Type: Oral
Mexico's historic public tender for its deepwater real estate resulted in the awarding of eight out of 10 blocks on offer. Held Monday in Mexico City, the event marked the fourth and final tender of the country's Round One process that has reopened the doors to foreign oil and gas firms for the first time since the energy sector was nationalized almost 80 years ago. A total of 13 companies were awarded rights to explore and produce from offshore fields in the Gulf of Mexico. The winning bids also committed to drill at least eight deepwater wells. All four blocks on offer in the Perdido area were awarded, including two that went to the Chinese Offshore Oil Corporation (CNOOC) and one to a consortium of Chevron, Pemex, and Inpex--Japan's largest oil company.
Mexico Awards Its First Deepwater Blocks; What Comes Next? The port of Dos Bocas, located along the coast of the Mexican state of Tabasco, is used to support jackup rigs and supply vessels but will need significant upgrades and expansion to become a deepwater facility. The nearby town of Dos Bocas also lacks many hotel rooms or an international airport. Held last December in Mexico City, the event marked the fourth and final auction of the country’s Round One, which reopened doors to foreign oil and gas investment for the first time since the country’s energy sector was nationalized almost 80 years ago. The awarded blocks went to 13 companies whose exploration and production operations are expected to generate around USD 34 billion over the next 15 years.