Murdoch, Euan (Weatherford Completion Systems) | Walduck, Steve (Weatherford UK Ltd) | Munro, Chris (Weatherford UK Ltd) | Edwards, Andrew (Weatherford) | Choquet, Caroline (Weatherford Energy Services)
Successfully deploying a single trip completion system in a deep-water environment requires an innovative technical solution to address the risks that come with this environment. Following a request from the operator for a deep-water single trip solution, a number of different system options were proposed. Each system was evaluated against the operator’s requirements, and a Radio Frequency Identification (RFID) technology-based system was selected as it offered the greatest flexibility in both activation and contingency methods to meet the demands of the project.
It was proposed to hold a 2 stage System Integration Test (SIT) at a test rig in Aberdeen. The first SIT was performed with a small number of tools that could be setup in different modes to prove the system’s logic against the operator’s expectations. Whilst this was conducted successfully a number of learnings and operational optimisations were captured. These were fed into a full-scale SIT which was deployed at the same test rig. This second SIT involved a complete representation of the single trip system and was designed to test the final system logic prior to deployment into an offshore environment.
The system was then installed successfully in November 2018, on a subsea well, offshore Nigeria with no intervention. It resulted in an operational time saving of at least 60% over the previous best recorded time for a conventional two-trip completion from the same rig. This represented a step change in operational efficiency and will now be the operator’s base case completion methodology as they develop the field further.
This is the first time a single trip completion has been deployed in this fashion in a deep-water, offshore environment. The demonstrable step change in operational time and resultant project OPEX savings, proves that the use of RFID and remote actuated tools within completions offer excellent alternatives to traditional methods.
It is often stated that necessity is the mother of invention. Never is this proverb more relevant than in the offshore oil and gas environment we currently operate in where real step changes leading to reduced capital and operational expenditure opportunities are sought and embraced by field operators. This paper discusses the pre-job planning, field execution and lessons learned from one such technology that challenged conventional thinking of sand faced completion, casedhole completion and well integrity to successfully deliver a single-trip, interventionless, sand control completion in deepwater Bonga Field, located on the continental slope of the Niger Delta.
Convention dictates that the vast majority of offshore completions be run in two and sometimes three trips which routinely takes in excess of eight to ten days to deploy. Given the day rate of high specification rigs capable of drilling in deep water environments, the ability to reduce this time was deemed paramount to the economics of the project. Utilizing a collaborative approach to initial concept design, risk assessment, extensive testing and contingency planning at component and system level, a single-trip, interventionless, sand control completion system was designed and successfully installed. This paper describes the completion architecture, operational sequence and challenges leading to the installation of an interventionless completion.
A clearly defined set of deliverables and design principles were drawn up to guide the direction of the project including: successfully deploying the upper and lower completion in one trip, and testing all barriers. Adopting a simple, low risk and high reward design, meeting clients well barrier requirements and utilizing proven cost-effective technology are examples of design principles used. The system was tested and evolved through a number of iterations in an onshore trial well environment on a number of occasions leading to the first successful deployment completed in the second half of 2018, resulting in an average completion installation time of 5 days, versus the average 10 days for deploying multi-trip completions. Details of the successful installations, lessons learned, along with planned future activity are outlined within the body of this paper. While several of the components incorporated in the single-trip system had been run previously in isolation, this paper also discusses the steps taken to facilitate the first full-system approach to the application of radio frequency identification (RFID) enabled tools in the first single-trip, interventionless sand control completion system. Several components within the completion have been equipped with this technology including a multi-cycle ball valve, wire wrapped screens fitted with inflow control device (ICD), remote operated sliding sleeve for annular fluid displacement.
The large independent put together a team of data scientists, software developers, and petrotechnical staff to create a forward-looking vision for how to use digital technology to solve problems. Baker Hughes is still a GE company, but it has partnered with a second company for artificial intelligence expertise, C3.ai. The deal is expected to speed the integration of AI into oilfield operations by the company which also markets GE’s device analytics platform, Predix. Marathon Oil says its shale fields are producing more oil and gas with less hands-on work from company personnel thanks to a growing arsenal of digital technologies and workflows. Malaysia’s Petronas, Shell Malaysia, and Thailand’s PTTEP are now in the midst of full-scale digital adoption.
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Hydrocarbon production potential is often limited by constraints, and it is important that these constraints are understood and correctly represented when generating a realistic set of production profiles. The focus of this section is physical constraints in the system through which the fluid flows, but constraints applied because of reservoir management, contractual terms and economics are also highlighted. A production system includes the reservoir, wells, facilities and export system. Constraints within the system can be associated with any of the produced fluids (oil, gas or water) or a specific combination of them. For example, important factors to consider beyond the base deliverability of the reservoir are potential near-wellbore formation damage (skin), well tubing constraints, artificial lift availability, shared gathering system back pressures, flow line erosion velocity limits and facility capacities.
Activity scheduling is an important, integral part of production forecasting that can have a significant impact on the reliability of the forecast. Once the subsurface input has been established and agreed upon by multiple disciplines, the production forecast should be created taking into account system constraints, scheduled and unscheduled downtime and new activities such as well and field optimization, changes to facilities capacity or design and new wells and developments coming on production. Future development programs are a major component of activity scheduling. The timeline and production impact of the drilling program is estimated and layered onto the existing baseline forecast (commonly known as the "no further activity forecast"). This is typically done using type curves or a simulation model because the wells are not yet on production.
The production forecast should be consistent with the current reservoir drainage strategy and should include production from existing and new wells, side-tracks and well interventions. Short-term forecasts are most dependent on activity levels (number and timing of new wells and well interventions), while long-term forecasts are more affected by reservoir type and the above-mentioned subsurface assumptions. The above reservoir description should be based on all available field data, the quantity and quality of which will vary considerably from asset to asset depending on field location, maturity and the level of appraisal and surveillance. Key data includes 2D/3D seismic, well logs, PVT analysis, core analysis and well tests. Static and dynamic reservoir understanding, G&G and petrophysical interpretations, reservoir modelling and detailed analysis of both the reservoir and well performance are key factors in establishing the most optimal drainage strategy.
The following guidelines are provided to promote consistency in production forecasting and reporting. "Reporting" refers to the presentation of evaluation results within the business entity conducting the evaluation and should not be construed as replacing guidelines for subsequent public disclosures under guidelines established by regulatory and/or other government agencies, or any current or future associated accounting standards. Commercial terms refer both to those specified in Production Operating Agreements (POA) and to the tax laws existing in the affected countries. The POA typically describes the production entitlement of the operating groups and the mechanisms for sharing or recovering costs. The majority of this document focuses on forecasting the total production from a reservoir or field (gross volumes forecast).
The explorer has so far encountered 400 ft of reservoir pay zone in an area where it has three other producing fields. Murphy Oil to Buy Deepwater US Gulf Assets for up to $1.625 Billion The El Dorado, Arkansas-based Murphy has quickly found a home for some of the cash it will receive from the sale of its Malaysia business. The company has been rapidly expanding its US gulf footprint while simplifying its portfolio and targeting more oil. Petrobras and Shell have brought online the Lula field’s seventh FPSO as the firms continue to ramp up production from the pre-salt Santos Basin. The French major is racking up barrels of deepwater production as part of its large-scale West African push.
The decision to invite bidders on Bonga South West/Aparo comes four-and-a-half years after production began on the Bonga North West development in the Gulf of Guinea. The Nigerian National Petroleum Corporation (NNPC) and Shell have invited prospective bidders to submit tenders for the execution of the $10-billion Bonga South West/Aparo (BSWA) deepwater project. The announcement comes 7 months after Shell and the NNPC received permission to begin the tendering process for the project. BSWA is expected to carry a peak production of 225,000 BOPD by 2022. Final investment decision (FID) on the project was initially set for 2014, but the project faced delays due to a number of factors, including the oil price downturn and high costs associated with deepwater developments.