Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Xu, Wei (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Fang, Lei (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC International Limited)
In complex clastic reservoirs, deviation often exists in oil saturation derived from logging interpretation due to the borehole conditions and log quality. Especially in thin-sand reservoirs, oil saturation is generally lower than actual results because of boundary effect. An innovative approach of saturation height function coupled with rocktype is provided to improve the accuracy of saturation prediction in well logs and spatial distribution. The model results are compared with log derived results.
The new approach is based on the routine and special core analysis of over 100 core samples from the complex clastic reservoir in the north of Albert Basin in Uganda. Discrete rocktypes (DRT) are determined by flow zone index and pore throat radius which indicate the fluid flows. After converting the capillary pressure (Pc) data to reservoir conditions, Lambda curve fitting (Sw = A * PcB + C) is used to fit each capillary pressure curve. Then, a robust relationship between the fitting coefficients (A, B, C) and rock properties (i.e. porosity and permeability) is expressed as a nonlinear function for each DRT. Combined with the height above free water level, a water saturation (Sw) model is constructed by SHF within DRT model.
Using the porosity and permeability obtainedfrom routine core analysis, FZI and pore throat radius are calculated (e.g., by Winland function). Five different rocktypes (DRT1-5) are defined in the delta sand reservoir in the north of Albert Basin with distinct pore textures. The distinguishment is in accordance with the shape of capillary pressure curve, that is, the flow capability increases from DRT1 to DRT5. A strong correlation between Pc and Sw processed by Lambda curve is acquired for each core sample. Meanwhile, 3 coefficients A, B and C can be obtained in Lambda formula. By nonlinear regression, coherent relation between each factor and reservoir properties (porosity and permeability) for each DRT are obtained. Height above the free water level is estimated by geometrical modeling on the oil water contact. The Sw model is constructed by the new SHF function coupled with DRT model. It showed that the water saturation derived from SHF is highly consistent with log derived results and NMR results. Moreover, it provides more precise results in thinner sands and in spatial distribution.
Based on the identified different rocktype, a new SHF derived from capillary pressure data is utilized to establish the relationship between saturation, the height above the free water level and rock properties. The approach can significantly improve the accuracy of saturation prediction of thin reservoir and reasonably depict the spatial distribution characteristics of saturation. Furthermore, the approach will provide a more precise result in hydrocarbon volume calculation and numerical simulation.
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.
Taha, Taha (Emerson Automation Solutions) | Ward, Paul (Emerson Automation Solutions) | Peacock, Gavin (Emerson Automation Solutions) | Heritage, John (Emerson Automation Solutions) | Bordas, Rafel (Emerson Automation Solutions) | Aslam, Usman (Emerson Automation Solutions) | Walsh, Steve (Emerson Automation Solutions) | Hammersley, Richard (Emerson Automation Solutions) | Gringarten, Emmanuel (Emerson Automation Solutions)
This paper presents a case study in 4D seismic history matching using an automated, ensemble-based workflow that tightly integrates the static and dynamic domains. Subsurface uncertainties, captured at every stage of the interpretative and modelling process, are used as inputs within a repeatable workflow. By adjusting these inputs, an ensemble of models is created, and their likelihoods constrained by observations within an iterative loop. The result is multiple realizations of calibrated models that are consistent with the underlying geology, the observed production data, the seismic signature of the reservoir and its fluids. It is effectively a digital twin of the reservoir with an improved predictive ability that provides a realistic assessment of uncertainty associated with production forecasts.
The example used in this study is a synthetic 3D model mimicking a real North Sea field. Data assimilation is conducted using an Ensemble Smoother with multiple data assimilations (ES-MDA). This paper has a significant focus on seismic data, with the corresponding result vector generated via a petro-elastic model. 4D seismic data proves to be a key additional source of measurement data with a unique volumetric distribution creating a coherent predictive model. This allows recovery of the underlying geological features and more accurately models the uncertainty in predicted production than was possible by matching production data alone.
A significant advantage of this approach is the ability to utilize simultaneously multiple types of measurement data including production, RFT, PLT and 4D seismic. Newly acquired observations can be rapidly accommodated which is often critical as the value of most interventions is reduced by delay.
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 well will immediately be brought on production and is expected to flow at more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said. The French major is racking up barrels of deepwater production as part of its large-scale West African push. Since 2007, an operator in Nigeria has registered a significant increase of oil-spill events caused by sabotage and oil-theft activities. The technology presented here allows detecting and locating leaks taking place at a distance from the sensor of up to 35 km.
The five discoveries combined hold an estimated 1.8 billion bbl of light oil in place. A major operator manages multiple deepwater projects in the Gulf of Guinea. This paper describes one of these, a recent 44-well project. The French major is racking up barrels of deepwater production as part of its large-scale West African push. Despite a trend toward renewables and low-carbon energy production among European majors, Total remains wholeheartedly committed to deepwater production.
The Italian operator reported positive appraisal and exploration results from wells drilled some 10,000 km apart. UK operator Trident Energy is entering Brazil while Australian firm Karoon Energy is expanding its position in the country. Both will try to boost output from already-producing assets. Findings from Kayrros suggest the average Permian well is both less productive and more expensive than reflected in public data. Mexican President Andrés Manuel López Obrador is prioritizing investment in Pemex over foreign participation as a means to boost the country’s shrinking oil output.
Anchored by the Khaleesi-Mormont and Samurai fields, the King’s Quay FPS will receive and process up to 80,000 B/D of crude oil. UK operator Trident Energy is entering Brazil while Australian firm Karoon Energy is expanding its position in the country. Both will try to boost output from already-producing assets. The world’s largest oil producer has awarded $18 billion in engineering, procurement, and construction contracts as part of its Marjan and Berri expansion projects. The Norwegian operator will increase its ownership of the giant Johan Sverdrup field before the field commences oil production this November.
Researchers from the Federal Reserve Bank of Dallas quantified the economic impact of the US shale revolution for the first half of this decade. Production from the Hibernia platform was shut down again on 17 August after its second oil spill in a month, while Husky Energy began to ramp up output from the White Rose field following the largest-ever spill off Canada’s easternmost province. Anchored by the Khaleesi-Mormont and Samurai fields, the King’s Quay FPS will receive and process up to 80,000 B/D of crude oil. Despite reports to the contrary, Permian well productivity remains healthy, with average new production per well in the basin matching all-time highs, Rystad says. Researchers mapped 251 faults in the North Texas home of the Barnett Shale, the birthplace of the shale revolution, finding that wastewater injection there “significantly increases the likelihood for faults to slip.”
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.