The Yibal Khuff/Sudair reservoirs were discovered in 1977. The field contains both Non-Associated Gas in the Sudair & Lower Khuff reservoirs and Associated Gas with oil rims in the Upper Khuff reservoirs. The Upper and Lower Khuff hydrocarbons contain 2–3% H2S and 4–6% CO2, whereas the Sudair gas contain 1–1.5% CO2 and less than 50 ppm H2S. The Field Development Plan (FDP), a multibillion dollar sour development project, was completed in 2011 proposing a total of 47 wells, 34 dedicated horizontal/vertical wells for oil rim production and 13 commingled vertical/deviated gas wells, and the construction of new sour surface facilities with a gas production capacity of 6 MMm3/day.
FDP execution started in 2016 while the details of field start-up, scheduled a few years later, were still being planned. As part of this planning, it was noticed that a number of pre-drilled wells required perforation and clean-up before facility startup. Due to the time necessary to prepare all the pre-drilled wells, pre-production wellbore cross-flow was expected to occur in wells located in the West block of the field. A dedicated subsurface team was assigned in 2017 to evaluate and mitigate the potential risks associated with this expected cross-flow through the wellbore resulting from the pressure difference between the Lower Khuff and Upper Khuff layers.
This paper covers the integrated approach that the team followed to address the expected cross-flow issue, including: Basis for pre-production cross- flow The quantification of the cross-flow using analytical and numerical simulation methods The assessment of the impact of cross-flow on process safety and the environment (i.e. drilling risks with potential blow out of sour gas) and social responsibility (i.e. production capacity and ultimate recovery losses resulting in lower benefits to the community) The identification and assessment of solutions to stop/reduce the cross-flow The implementation of a robust and feasible mitigation plan
Basis for pre-production cross- flow
The quantification of the cross-flow using analytical and numerical simulation methods
The assessment of the impact of cross-flow on process safety and the environment (i.e. drilling risks with potential blow out of sour gas) and social responsibility (i.e. production capacity and ultimate recovery losses resulting in lower benefits to the community)
The identification and assessment of solutions to stop/reduce the cross-flow
The implementation of a robust and feasible mitigation plan
The conducted study demonstrated that the impact of cross-flow at well level would be severe. The cross-flow rate could reach up to 25-137 Km3/day/well, while the field level cross-flow rate could reach up to 400 Km3/day. The oil rate capacity reduction in the West Block wells could reach 20-30% at start-up, resulting in a total only 1% oil ultimate recovery loss at field level since the West block contribution is small to total production and West block wells are constrained. The study also showed that the casing design is adequate and drilling risks are manageable even in case of cross-flow. Out of several solutions identified to stop/reduce cross-flow, phasing perforation was considered the most robust and feasible option.
This paper presents the novel approach of a collaborative study that resulted in improved safety and reduced environmental risks and potential ultimate recovery losses. It also presents the methodologies used to allow the Assessment and Mitigation of Pre-Production Cross-flow and evaluation of the best option to mitigate the cross-flow in order to minimize the impact of cross-flow at minimum cost, well interventions and impact on well deliverable.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Araujo, Mariela (Shell International Exploration and Production Inc.) | Chen, Chaohui (Shell International Exploration and Production Inc.) | Gao, Guohua (Shell International Exploration and Production Inc.) | Jennings, Jim (Shell International Exploration and Production Inc.) | Ramirez, Benjamin (Shell International Exploration and Production Inc.) | Xu, Zhihua (ExxonMobil) | Yeh, Tzu-hao (Shell International Exploration and Production Inc.) | Alpak, Faruk Omer (Shell International Exploration and Production Inc.) | Gelderblom, Paul (Shell International Exploration and Production Inc.)
Increased access to computational resources has allowed reservoir engineers to include assisted history matching (AHM) and uncertainty quantification (UQ) techniques as standard steps of reservoir management workflows. Several advanced methods have become available and are being used in routine activities without a proper understanding of their performance and quality. This paper provides recommendations on the efficiency and quality of different methods for applications to production forecasting, supporting the reservoir-management decision-making process.
Results from five advanced methods and two traditional methods were benchmarked in the study. The advanced methods include a nested sampling method MultiNest, the integrated global search Distributed Gauss-Newton (DGN) optimizer with Randomized Maximum Likelihood (RML), the integrated local search DGN optimizer with a Gaussian Mixture Model (GMM), and two advanced Bayesian inference-based methods from commercial simulation packages. Two traditional methods were also included for some test problems: the Markov-Chain Monte Carlo method (MCMC) is known to produce accurate results although it is too expensive for most practical problems, and a DoE-proxy based method widely used and available in some form in most commercial simulation packages.
The methods were tested on three different cases of increasing complexity: a 1D simple model based on an analytical function with one uncertain parameter, a simple injector-producer well pair in the SPE01 model with eight uncertain parameters, and an unconventional reservoir model with one well and 24 uncertain parameters. A collection of benchmark metrics was considered to compare the results, but the most useful included the total number of simulation runs, sample size, objective function distributions, cumulative oil production forecast distributions, and marginal posterior parameter distributions.
MultiNest and MCMC were found to produce the most accurate results, but MCMC is too costly for practical problems. MultiNest is also costly, but it is much more efficient than MCMC and it may be affordable for some practical applications. The proxy-based method is the lowest-cost solution. However, its accuracy is unacceptably poor.
DGN-RML and DGN-GMM seem to have the best compromise between accuracy and efficiency, and the best of these two is DGN-GMM. These two methods may produce some poor-quality samples that should be rejected for the final uncertainty quantification.
The results from the benchmark study are somewhat surprising and provide awareness to the reservoir engineering community on the quality and efficiency of the advanced and most traditional methods used for AHM and UQ. Our recommendation is to use DGN-GMM instead of the traditional proxy-based methods for most practical problems, and to consider using the more expensive MultiNest when the cost of running the reservoir models is moderate and high-quality solutions are desired.
Khamees, Tariq K. (Missouri University of Science & Technology) | Flori, Ralph E. (Missouri University of Science & Technology) | Alsubaih, Ahmed A. (Basra Oil Company) | Alhuraishawy, Ali K. (Missan Oil Company)
In-depth gel treatment is a chemical EOR process used to improve the sweep efficiency from heterogeneous reservoirs with crossflow. However, if these reservoirs are saturated with viscous oil, polymer and surfactant flooding should be combined with in-depth gel treatment. Thus, in this study, a 3D model using the UTGEL simulator was built to model in-depth gel treatment combined with surfactant slug and polymer solution. The model was represented by one quarter of the five-spot pattern with eight layers where two thief zones are located in the middle of the model. The thief zones had a permeability of 1500 md with a total thickness of 20 ft, while the rest of the layers had a permeability of 100 md with a total thickness of 200 ft.
The gel system consisted of a polyacrylamide/Cr(VI)/thiourea solution, which is considered an in-situ gelation system. Gelant solution was injected for 60 days when the water cut in the model reached 65%, followed by surfactant slug for 2 years, polymer solution for 3 years, and then post-water injection for the rest of the simulation time. The concentrations of the surfactant ranged from 0.01 to 0.2 wt.%, while the polymer concentration was 1,000 ppm. The injection rate was 1,070 bbl/day during all flooding and treatment processes.
The results showed that it is imperative to implement surfactant with gel treatment to reduce the interfacial tension between water and oil phases and to alter the wettability of the reservoir rocks. Thus, gel treatment alone or gel followed by polymer was not as efficient as the injection of a surfactant slug. The results also showed that as the reservoir temperature increased, the overall performance of gel, polymer, and surfactant decreased. Therefore, the higher the temperature, the lower the recovery factor. The results also revealed the importance of viscoelastic behavior of the HPAM polymer solution where higher results for both water-wet and oil-wet conditions were obtained compared to shear-thinning behavior only. Moreover, the results revealed interesting behavior regarding the concentration of the surfactant, where the recovery factor increased as the concentration of the surfactant increased in oil-wet conditions. However, in water-wet conditions, the results were unpromising and unfavorable. Furthermore, the injection of surfactant directly after the gel treatment was more effective in improving the sweep efficiency than the injection of polymer directly after the gel treatment. Finally, as the salinity of makeup water and/or reservoir brine increased, the recovery factor decreased for both water and oil-wet systems. This is because, as salinity increased, the adsorption of both polymer and surfactant increased and the polymer viscosity decreased. Furthermore, the presence of divalent cations such as Ca+2 and Mg+2, would have a negative impact on overall treatment.
The Middle to Late Cretaceous Natih formation in Oman can be highly compressible and undergo large compaction during depletion. Significant reservoir compaction and surface subsidence has potential risks for fault reactivation, integrity of wells and surface facilities. Petroleum Development Oman produces oil and gas from the Natih formation in a number of fields within its concession area. There are existing experiences in one of the analogue field in Oman, where the compaction of Natih formation has resulted in issues of well damage, well integrity, subsidence damage to facilities and experiences of surface tremors due to fault reactivation.
The focus of this work was for Fahud West oil field producing oil and gas from a Natih reservoir, where analysis of an analogue field had indicated a high potential impact of compaction. A Geomechanical assessment of the formation within the field was therefore undertaken to mitigate operational risks, and to assess the permeability impact with increased depletion.
The Integrated Geomechanical data acquisition and modeling minimized uncertainty and provided clarity on whether the reservoir can continue with increased depletion – without increased geomechanical risks of loss of integrity for wells and facilities, cap rock integrity or reduced productivity. Properly planned and rock mechanics measurements were conducted in the laboratory on core samples.
The measurements revealed that the expected compaction of Natih reservoir in Fahud West field is less severe compared to the analogue field. The maximum predicted surface subsidence expected at depleted reservoir pressure of 10 bars, is within the tolerable subsidence limit for surface facilities. In addition, permeability measurements showed that the permeability at reservoir pressure of 22 bars (the previous base case for end of production), will not change significantly with further depletion of reservoir pressure to as low as 10 bars.
The outcome of this integrated geomechanical assessment demonstrates that the field can be produced down to 10 bars from the previously estimated 22 bars (base case) limit, adding significant risked volume of oil production, allowing further drilling of wells to raise the final field recovery while ensuring safe well and facility integrity
Mahajan, Sandeep (Petroleum Development Oman) | Stammeijer, Jan (Petroleum Development Oman) | Mukhaini, Hamed (Petroleum Development Oman) | Azri, Saif (Petroleum Development Oman) | Rahmoune, Rachid (Petroleum Development Oman) | Aamri, Mohammed (Petroleum Development Oman) | Tarmizi, Ikhsan (Petroleum Development Oman)
One of the PDO's largest producing fields in Oman consists of three stacked reservoir formations, two of which are currently producing while deeper reservoirs are being considered for development. The shallowest reservoir (~ 900 m depth) is a highly compacting carbonate gas reservoir under depletion, whereas the intermediate reservoir Shuaiba is an oil-bearing reservoir under water flood. The deeper reservoirs are oil and gas bearing located in the Sudair and Khuff formations.
Interpretation of 3D seismic data shows a major NE/SW and NW/SE fault system in all 3 reservoirs. Depletion in the shallow gas reservoir, which exhibits pore collapsing response on depletion, has induced surface subsidence which is active and expected to reach about 2.4 m at the end of field life. Subsurface deformations and induced stress changes have resulted in subset of the faults (NE/SW) to reactivate, causing seismic tremors, occasionally felt at surface.
Ongoing surface subsidence has resulted in some damage to surface facilities and subsurface well integrity issues. Furthermore, fault reactivation and/or loss of well integrity may induce leakage pathways for reservoir fluids to cross flow between reservoirs or to shallow aquifers. PDO has implemented an extensive monitoring program supported by parallel 3D geomechanical modeling studies, to manage ongoing field development whist mitigating the risks.
Extensive monitoring efforts using a variety of techniques are in place since 1999. Frequent InSAR satellite data measures surface subsidence with such high accuracy and resolution that local zones of higher deformation can be reliably identified and flagged. Continuous GPS data acquisition in a few places throughout the field allows for detailed temporal assessment of subsidence and forms the basis for predictions of total subsidence at end of field life. Periodic in-well compaction monitoring data provides insights in elastic and non-elastic deformation at reservoir layer scale, which is compared against core compressibility data. Continuous microseismic monitoring in a dozen or more observation wells highlights geomechanically active faults in the main reservoir, overburden and underburden, thereby identifying potential risk zones on a near-24/7 basis.
All of this data is used both for well and facilities management, and for providing calibration data for geomechanical models. Results provide clarity on future surface subsidence and differential settlement, which helps to identify facilities with potential risk. The project teams are provided with reliable predictions of surface subsidence throughout the field to ensure the current design tolerance is adequate for integrity of the facilities until the end of field life. This paper presents modeling workflow and calibration with monitoring data related to the geomechanical assessment.
Temizel, Cenk (Aera Energy) | Kirmaci, Harun (Freelance Consultant) | Inceisci, Turgay (Turkish Petroleum) | Wijaya, Zein (HESS) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Al-Otaibi, Basel (Kuwait Oil Company) | Al-Kouh, Ahmad (Middle East Oilfield Services) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University)
Diatomites are high-porosity, low-permeability reservoirs with elastoplastic properties and high geo-mechanical responsiveness. They have a great potential for oil recovery despite these drawbacks. Withdrawal of fluids from the reservoir rock leads to subsidence causing compaction and shear stresses. This disturbed stress distribution results in well failures that causes loss of millions of dollars. Successful maintenance of pressure support through optimum injection/production is key to preventing subsidence to mitigate the risk of well failure and achieve better sweep efficiency for recovery.
There have been different approaches to tackle subsidence and well failures in diatomites, including the use of ‘backpressure method’, coupled with a neural network to optimize injection-production to ‘balance’ the rock in terms of stress-distribution and thus decrease well failure due to shearing. However, using such methods may mask other problems the well is experiencing including several mechanical issues that influence production. Another existing approach, satellite-imaging (InSAR) cannot be used to take real-time actions that is crucial in diatomites.
Surface tiltmeter data is collected to undertsand the relationship between injection/production and resulting surface deformation, which also provides information about well-to-well connectivity. A neural network-based approach is followed to determine the nonlinear relationship between surface subsidence/dilation and injection-production. This is then used to build an objective function that works to minimize the differences between well-to-well subsidence/dilation measured by the tiltmeters, by adjusting injection-production for the wells.
In this paper, a method that harnesses real-time surface tiltmeter data to adjust injection-production distribution in diatomites to decrease well failures is used beyond the existing applications of surface tiltmeter, for instance, in the areas of detection of early steam breach to surface in steam operations and fracture orientation. This method also provides real-time data for robust reservoir management of such reservoirs where satellite imaging is not effective.
ESP failures have important economic implications for O&G operators, including: nonproductive time, production deferral, production losses, and high cost of ESP replacements, especially for offshore or remote wells.
Improving Electric Submersible Pump (ESP) system reliability, eliminating or reducing failures, comprise the most frequent requests from O&G operators. But, how much reliability is enough? What is the cost of increasing reliability? What are the strategies to achieve it? ESP operators and vendors struggle when questions like these arise.
This paper explores the subject of ESP reliability in depth. It reviews key concepts of ESP maintainability and run life. It addresses the questions of how reliability of ESPs is measured, what the current levels of ESP reliability are and how much reliability is actually needed. It proposes a methodology to estimate potential savings as a result of reliability improvement and a method to calculate the optimum level of investment in ESP reliability.
Improving Electric Submersible Pump (ESP) system reliability, eliminating or reducing failures, comprise the most frequent requests from O&G operators. Over the last few decades, notable design improvements have been made with the use of computer aided design, rapid prototyping techniques, and use space age materials. But the average ESP run life has increased marginally, and remains at around three years.
ESP failures have important economic implications for O&G operators, including: nonproductive time, production deferral, production losses, and high cost of ESP replacements, especially for offshore or remote wells. Operators have tried different approaches to incentivize ESP vendors to improve ESP reliability, including: performance based contracts, internal research, open research, joint industry projects, and market competition. Despite these efforts, the goal of a ten-year run life remains elusive.
Saudi Aramco has set a very aggressive target of operating ESPs for an average of ten years without failure. This paper explores the likelihood of developing an ultra-reliable submersible pump system that can meet this challenging objective. It discusses the fundamental issues that currently prevent achieving higher ESP reliability, and also evaluates potential approaches to the reliability improvement challenge. Finally, the paper examines technical, operational, economic and market implications of such alternatives, for both O&G operators and ESP vendors