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This page pulls together technology-focused articles from various departments within JPT. The industry increasingly relies on forecasts from reservoir models for reservoir management and decision making. However, because forecasts from reservoir models carry large uncertainties, calibrating them as soon as data come in is crucial. The complete paper analyzes the role of liquefied natural gas (LNG) in balancing the natural gas demand in the Middle East/North Africa (MENA) region. Steam-assisted gravity drainage (SAGD) performance in bitumen-recovery projects in Alberta is affected by geological deposits, reservoir quality, and operational experience. In 2019, the US experienced the lowest natural gas prices since 2016. This was despite natural gas consumption increasing in the residential and commercial sector by 2% (between October and December) according to the US Energy Information Administration. The complete paper presents an integration of geology, geohazards, geophysics, and geotechnical assessments for a design of an offshore gas production facility and an associated export pipeline. The synopses in this feature show how machine learning can provide accurate prediction of annular pressure buildup, first-year oil production, and (in conjunction with novel casing accessories) the time and location of water breakthrough along a lateral wellbore. In this paper, the authors introduce a new technology installed permanently on the well completion and addressed to real-time reservoir fluid mapping through time-lapse electromagnetic tomography during production or injection. Proper lateral and vertical well spacing is critical for efficient development of unconventional reservoirs. Much research has focused on lateral well spacing but little on vertical spacing, which is challenging for stacked-bench plays such as the Permian Basin. Reviewing a myriad of papers presented at different conferences during the past year, I can group the current trends in heavy-oil operations and research into two major categories: Process optimization and use of chemicals as additives to steam and water. Although polymer flooding has become a promising enhanced oil recovery (EOR) technique, no field tests have been performed to date in Alaska’s underdeveloped heavy-oil reservoirs. The complete paper describes piloting the collection and analysis of distributed temperature and acoustic sensing (DTS and DAS, respectively) data to characterize flow-control-device (FCD) performance and help improve understanding of steam-assisted gravity drainage (SAGD) inflow distribution.
Rachapudi, Ramarao Venata (ADNOC ONSHORE) | Alshehhi, Shamma (ADNOC ONSHORE) | Saadwai, Omar (ADNOC ONSHORE) | Ayidinoglu, Gokhan (ADNOC ONSHORE) | Dodan, Cornel (ADNOC ONSHORE) | Khaled, Moutaz Faysal (ADNOC ONSHORE) | Quintero, Fernando (ADNOC ONSHORE) | Mubarak, Saber (ADNOC ONSHORE) | Gali, Appala Raju (ADNOC ONSHORE) | Mohammed, Samy (ADNOC ONSHORE) | Ikogho, Brume (Schlumberger Oil field Services)
Effective reservoir management is critical to the success of water flood developments. Continuous monitoring of downhole parameters such as pressure, temperature and flow profile in water injector wells is vital in order to optimize the water-flood sweep efficiency and to avoid early water breakthrough in nearby oil producer wells. The target field has three stacked tight carbonate reservoirs with low reservoir energy and as such is being developed with water injection scheme from day one. As such, effective monitoring of downhole injection parameters is important from an early stage.
A common industry practice to monitor these parameters is to install Permanent Downhole Gauge (PDHG) and Distributed Temperature Sensing (DTS) system. Recently, a new smart Hybrid Technology has been developed to measure the downhole data at surface. This paper describes the successful application of this hybrid technology in a green onshore oil field development. Details are presented about the well bore segmentation design of the DTS system, the hybrid cable installation and the operational challenges with the hookup to the wellhead control system. The paper also presents the data acquired during commissioning job, and interpretation of the temperature data which was used to generate the injection profile along the wellbore. Finally, a strategy for future implementation of the DTS system is discussed.
Overall, this technology showcases the application of the smart hybrid completion for real-time monitoring of the water injection profile, including the pressure and rates along with injection volume per segment in the horizontal section. Real-time data from the hybrid technology has been integrated to digital oil field implementation to enhance the real time decision making to optimize the injection rates and to allow the operator to implement the decisions without any delay. This technology optimized the cables requirement and maximized the utilization of cable for multi-application environment to support acquiring Pressure, DTS and DAS data to generate real time injection profile.
Santin, Y. (Halliburton) | Matar, K. (Halliburton) | Montes, E. (Halliburton) | Gorgi, S. (Halliburton) | Joya, J. (Halliburton) | Bu-Mijdad, M. (KOC) | Al-Mubarak, H. (KOC) | Al-Lafi, M. (KOC) | Al-Hamad, A. (KOC) | Al-Askar, H. (KOC) | Al-Shamaa, M. (KOC) | Al-Enizi, O. (KOC) | Bu-Qurais, A. (KOC) | Madhavan, S. (KOC) | Al-Dashti, M. (KOC)
Injection profile enhancement has been one of the primary objectives for an operator in Kuwait. Stimulation interventions in injector wells directly affect the enhancement of oil recovery in producer wells. This paper presents the application of a verifiable stimulation intervention in a water injector well to help achieve the operator's objectives.
The intervention presented several challenges. There was limited information available for the newly drilled carbonate formation under consideration in the Greater Burgan Field. Additionally, the fiberglass well tubing required significant attention before running in hole (RIH) with coiled tubing (CT). A high concentration of H2S was identified in Formation A; therefore, gas returns were also a potential issue. This paper discusses the methods used to help address these challenges. During this case study, real-time fiber-optic cable CT (RTFOCT) technology was applied in the fiberglass tubing injector well to determine initial well injection profile and adjust treatment accordingly. This technology includes a fiber-optic cable integrated into the CT pipe and a modular sensing bottomhole assembly (BHA).
RTFOCT technology allows for rigless operations and performs interval diagnostics, stimulation treatment, and evaluation in a single CT run. During this case study, the well injectivity increased by more than 100%. Diagnostics and evaluation were performed by analyzing the well thermal profile using fiber-optic distributed temperature sensing (DTS). The BHA helped ensure accurate fluid placement during the treatment using real-time pressure, temperature, and depth-correlation sensors. The RTFOCT technology provided real-time downhole information that was used to analyze reservoir parameters, help ensure accurate fluid placement, and enable quick and smart decisions regarding the stimulation treatment stages based on the fluid intake in different zones. During injection, the heterogeneous fluid flow became homogeneous along the interval confirmed with the thermal-hydraulic model (THM). This helped reliably complete the intervention operations and delay possible water breakthrough in the producer wells and extended reservoir recovery.
Gonzalez, Santiago (Kuwait Oil Company) | Al Rashidi, Hamad (Kuwait Oil Company) | Pandey, D. C. (Kuwait Oil Company) | Al-Mula, Yousef (Kuwait Oil Company) | Safar, Abdualaziz (Kuwait Oil Company) | Al-Kandari, Jassim (Kuwait Oil Company) | Abdalla, Waeil Abdelmohen (Kuwait Oil Company) | Gorgi, Sam (Halliburton) | Patel, Dipen (Halliburton)
Kuwait Oil Company (KOC) is running two pilot projects in South Ratqa Field to evaluate steam injection using cyclic steam stimulation (CSS) and steam flooding (SF) methods. These projects are the first of their kind in KOC history and one of the major milestones in the North Kuwait Heavy Oil Development.
Two large-scale thermal pilot (LSTP) projects are located north and south of the South Ratqa Field, with the north running two different areas of 10 and 5 acres and well completion and the south running one area of 5 acres.
KOC has been injecting steam in these pilots in an unconsolidated high viscous formation since 2015, beginning with a CSS process that migrating to SF during the second half of 2017. A fundamental goal to help ensure success with this type of project is carefully monitoring the injected steam per well and per formation layer by installing fiber optic distributed temperature sensing (DTS) and pressure gauges in a portion of the wells; this goal was defined at the beginning of the project. For this purpose, 12 wells were drilled as observation wells and 6 idle wells were used for fiber-optic deployment to monitor the reservoir 24 hours a day, 7 days a week for the injection life of the pilots. The observation wells with DTS and pressure gauges were distributed along the pilots to cover a large predetermined observation area for the pilots.
The observation wells with DTS and pressure gauges in the north and south LSTP areas were also distributed along these pilots to cover a large area. The benefits of installing this technology in the pilots are to: To develop an understanding of steam breakthrough zones along the pay-zone interval of production wells To help improve the understanding of the steam injection profile for steam-injector wells To help improve the real-time temperature profile along the length of producer’s wellbore To develop an understanding of heat management during steam flooding
To develop an understanding of steam breakthrough zones along the pay-zone interval of production wells
To help improve the understanding of the steam injection profile for steam-injector wells
To help improve the real-time temperature profile along the length of producer’s wellbore
To develop an understanding of heat management during steam flooding
This paper discusses the success story between two companies installing DTS and thermal pressure gauges and includes a description of DTS, the installation procedure of downhole and surface equipment, real-time data transfer, and data analysis.
AlMahrooqi, S. (Petroleum Development Oman) | Guntupalli, S. (Petroleum Development Oman) | AlMjeni, R. (Petroleum Development Oman) | Choudhury, S. (Petroleum Development Oman) | Hashmi, M. Al (Petroleum Development Oman) | Abri, A. Al (Petroleum Development Oman) | Azri, N. Al (Petroleum Development Oman)
Enhanced Oil Recovery (EOR) processes are key to Petroleum Development Oman (PDO) longer term business performance. To date, PDO is operating four commercial scale EOR projects and a number of pilots that are either ongoing or recently concluded. The EOR projects and pilots cover chemical and thermal EOR as well as miscible gas injection.
Successful EOR projects require robust long term strategic plans with built-in flexibility and seamless execution, in order to continuously de-risk associated uncertainties through proper testing and piloting. One of the key contributors to PDO's successful EOR journey has been successful monitoring and surveillance through acquisition of high quality surveillance data.
An alkaline surfactant polymer (ASP) pilot, first of its kind in PDO was recently concluded with encouraging results. Key pilot successes parameters included achieving reduction of oil saturation to less than 10% in one layer at the observation well. The challenge of saturation monitoring through salinity independent and carbon insensitive technique in EOR fields was addressed by Nuclear Magnetic Resonance (NMR) time-lapse cased hole logging through fiber-reinforced plastic (FRP) casing. The other ongoing EOR pilot involves injecting polymer into a heavy oil bearing reservoir with a strong bottom aquifer drive. In this pilot, the key subsurface uncertainties are polymer injectivity, conformance and sweep efficiency. These uncertainties are being de-risked by deploying monitoring technologies such as distributed temperature sensing (DTS), distributed acoustic sensing (DAS), Pressure monitoring and time-lapse saturation logging based on both nuclear and electrical principals.
Some of the challenges in the miscible gas injection project include; gas breakthrough evaluation, reservoir connectivity, and gas sweep efficiency. These were assessed by implementing inter-well tracer test, production and time-lapse saturation loggings.
Surveillance in Thermal EOR project (cyclic steam soak, CSS) revolves around having dedicated temperature, pressure observation wells and systematic temperature surveillance across the field. Assessment of steam injection profile and steam quality has also been focus areas. The aim is not only to monitor areal and vertical sweep efficiency (of both steam and reservoir fluids) over time, but also to get leading signals for a proper reservoir management to maximize profitability. Further, pattern recognition from microseismic survey data helps monitoring the ‘cap-rock’ integrity and reservoir containment. Production logging in the ultra high viscosity oil zone still remains a challenge.
Detailed fiber optics reservoir monitoring was implemented in Thermal EOR in naturally fractured carbonate reservoir. The objectivities are the oil rim-management and safeguard the cap-rock integrity from fault re-activation
In this paper, PDO's experiences in handling EOR challenges and how different EOR monitoring and surveillance technologies were utilized will be presented. A recommended practice will be discussed based on PDO's experience.
Staveley, C. (Smart Fibres Ltd) | Doyle, C. (Smart Fibres Ltd) | Coetzee, C. (Smart Fibres Ltd) | Franzen, A. (Shell Global Solutions International BV) | Boer, H. Den (Shell Global Solutions International BV) | Rooyen, A. van (Shell Global Solutions International BV) | Birch, W. (Shell Global Solutions International BV) | Biderkab, A. B. (Petroleum Development Oman) | Moes, E. (Petroleum Development Oman)
To efficiently produce an oil rim and not the overlying gas cap or the aquifer below, it is important to be able to monitor the oil rim position. In highly fractured carbonate reservoirs the conventional method of monitoring oil rim movement is by periodically running wireline gradio surveys. However, some operators have found this method to be inconclusive and unable to provide information in a sufficiently timely manner to influence operations as the gradio surveys are only run a few times a year. We describe a project to design, field trial and qualify an alternative solution for real-time monitoring of the oil rim in carbonate reservoirs which overcomes these disadvantages.
Al Shoaibi, S. (Petroleum Development) | Kechichian, J. (Petroleum Development) | Mjeni, R. (Petroleum Development) | Al Rajhi, S. (Petroleum Development) | Bakker, G. G. (Petroleum Development) | Hemink, G. (Shell Global Solutions International B.V) | Freeman, F. (Shell Global Solutions International B.V)
Fiber Optics Distributed sensing technologies are evolving in the petroleum industry with its potential applicability in many areas of surveillance. Petroleum Development Oman (PDO) is embarking upon the implementation of this technology in various assets including both Gas and Oil fields. The vision of the company is to have the Fiber Optics distributed sensing technology as a surveillance tool in the Well and Reservoir Management (WRFM) toolbox and to become, where appropriate, a key element of its cycle. In comparison to conventional surveillance, fiber optic distributed sensing requires no well intervention and thereby reducing HSSE exposure and production deferment. In addition, the installed fibers can be used for multiple applications, e.g. hydraulic fracture performance monitoring and inflow performance monitoring. Recently, PDO trialed Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) technologies utilizing both, dip-in surveys and permanent installation of fiber optics in the wells.
Fiber optic implementation in PDO included a polymer flooding trial in heavy oil, high permeability clastic reservoir with a strong bottom water aquifer drive. The objective was to monitor well conformance as the polymer injection progressed. The horizontal injectors were completed with pre-drilled liner and divided into four zones, each with an independent Inflow Control Valve (ICV). The well was completed with a multi-mode (MM) fiber pumped into control lines three injectors. Real time DTS data was acquired continuously in all three wells while DAS was acquired as per the injection program in one injector. DAS and DTS data were analyzed to quantify the changes in injection profile and rate in each ICV zone. This provided timely information needed for decisions related to manipulation of the ICV valves to ensure best utilization of the polymer.
Another example of fiber optics was a dip-in survey in a deep gas well with commingled production which covered stacked reservoirs. This was run in order to prove the concept of flow response on DAS/DTS signals in terms of gas flowing and liquid lifting detection. The acoustic signature observed was mainly due to gas entering the well through perforations. This was detected by DAS and DTS and allowed a qualitative inflow profile to be generated. The dip in survey proved the concept and allowed justification for the permanent installation of fiber optics behind casing. The objective of the permanent setup is to improve the sensitivity of the measurement and allow for better quantification of inflow per zone. In this paper, the approach of implementing fiber optic technologies in PDO is discussed with emphasis on value generation in the various assets. Additionally, the examples mentioned in this abstract are discussed in more details and based on the results, the way forward is described.
Intelligent Reservoir Management and Monitoring has played a key role in the pursuit of improving the hydrocarbon recovery and reducing the development expenditure in the challenging multi-stacked compartmentalized fields which have proved to be perplexing in a number of ways which include preventing or delaying water breakthrough, extenuating wellbore instability, sand production etc.
Reservoir-management and monitoring options have been greatly improved in recent decade by smart completions comprising of downhole monitoring and control equipments like permanent down-hole gauges to have “eyes” into the reservoir and to monitor performance for each zone; dynamic active flow control valves, which aid in equalization of the reservoir inflow into the wellbore; and the SCADA system which enables the real time monitoring and control of the downhole and surface equipment remotely from the control room.
Proper application of this methodology can be one of the most lucrative ventures that an operator undertakes, by delaying water breakthrough problem to recover additional monthly cumulative production than a conventional production method in such reservoirs. This method also results in avoiding the heavy intervention expenses, extending economic life of the field, improving reservoir management, zonal isolation, allowing real time well testing, fewer wells and less operating expenditures.
This paper discusses real field design methodology and outcomes of different wells that resulted in restoring the production by greater than 1000 B/D, minimizing the OPEX by eliminating huge cost oriented interventions of $10 MM (per intervention), saving Millions of Dollar investments as CAPEX via IWC re-completion with multi-lateral technology and an augment of EUR of about 2 MMSTB per well. The paper also enlightens a comprehensive logic guideline towards the tool box of the technology, including the applied workflow, procedures and standards with the field examples and desired results.
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Intelligent Energy Conference and Exhibition held in Utrecht, The Netherlands, 1-3 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Kuwait Integrated Digital Field Gathering Center 1 (KwIDF-GC1) pilot project was launched in Burgan field in 2009 as an investigation into how a cross-functional and cross-domain infrastructure could be established to aid in the achievement of corporate goals set for the following two decades. The company's vision for 2030 includes a philosophical shift in the way that the country's workforce accomplishes its tasks, employing latest technologies and work processes. The project solution integrates field instrumentation with workflows automated in software and focused collaboration. All well sites were instrumented with pressure and temperature gauges, multiphase water cut meters, remotely automated chokes and electronic H 2 S detectors. Automation of field was the first step in providing the advanced technology required of this project, realizing tangible advantages in minimizing the health, safety and environmental (HSE) exposure of field personnel. Well site data can be read, and choke positions can be set, remotely at the gathering center without the need for field personnel to enter hazardous areas. The implementation is digital throughout, employing a field-level WiMAX radio system to provide fast and secure Ethernet-based communication from gathering center to the wellhead.