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.
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.
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
Al-Hadhrami, M. (Petroleum Development Oman) | Ferrero, M. Boya (Shell Intl. E&P BV) | Kawar, R. (Shell Intl. E&P BV) | Unal, E. (Shell Intl. E&P BV) | Wahaibi, A. (Petroleum Development Oman) | Bazalgette, L. (Shell Intl. E&P BV) | Al-Farsi, S. (Petroleum Development Oman) | Khabouri, K. (Petroleum Development Oman)
This paper discusses the interpretation of historic data for a giant and COMPLEX fractured carbonate, leading to a different understanding of the reservoir's displacement processes, and renewed insights for future development opportunities.
Specifically, the paper describes a comprehensive study to Locate The Remaining Oil (LTRO) and improve the ultimate performance of the field. The study encompassed the integration of recent seismic datasets, BHI (Borehole Imaging) data from over 100 wells, well logs for key wells at different time lapses, core data for different facies, well performance and interference data. Focus has also been placed on understanding the various recovery mechanisms that the field has undergone (water injection and Gas-Oil Gravity Drainage (GOGD) concurrently in different regions of the field). This LTRO exercise has provided insights into the distribution and intensity of inter- and intra-faults and the fracture connectivity between the field units. This warrants clustering the giant field into "development districts" i.e. to move from layer-based development to acknowledgment of vertical communication between layers It has become apparent that the reservoir architecture and fluid flow characteristics in this giant reservoir benefits from a secondary system of background fractures. The future field development concept should target- the matrix blocks with background fractures holding remaining oil for a slow GOGD development.
The study is part of continued efforts to build a centre of excellence in PDO around Naturally Fractured Carbonate Reservoirs, and to help unlock reserves in PDO's extensive portfolio of NFR (Naturally Fractured Reservoir) Carbonate fields.
The complexities involved in the available reservoir simulation model for the geologic CO2 sequestration study at SACROC Unit, lead to a high computational cost nearly impractical for different types of reservoir studies. In this study, as an alternative to the full-field reservoir simulation model, we develop and examine the application of a new technology (Surrogate Reservoir Model – SRM) for fast track modeling of pressure and phase saturation distributions in the injection and post-injection time periods.
The SRM is developed based on a few realizations of full-field reservoir simulation model, and it is able to generate the outputs in a very short time with reasonable accuracy. The SRM is developed using the pattern recognition capabilities of Artificial Intelligence and Data Mining (AI&DM) techniques. The SRM is trained based on the provided examples of the system and then verified using additional samples.
The intricacy of simulating multiphase flow, having large number of time steps required to study injection and post-injection periods of CO2 sequestration, highly heterogeneous reservoir, and a large number of wells have led to a highly complicated reservoir simulation model for SACROC Unit. A single realization of this model takes hours to run. An in-depth understanding of CO2 sequestration process requires multiple realizations of the reservoir model. Consequently, using a conventional numerical simulator makes the computational cost of the analysis too high to be practical.
On the other hand, the developed SRM for this case study runs in a matter of seconds. The comparison between the results of SRM and simulator, during training and verification steps of SRM development, demonstrates the ability of SRM in mimicking the behavior of numerical simulation model. The results of this study are intended to prove the potential of AI&DM based reservoir models, like SRM, to ease the obstacles involved in the conventional CO2 sequestration modeling.
A recent series of tight gas discoveries in the Amin format ion of the greater Fahud area represents some of the most exciting exploration success of this decade in the Sultanate of Oman. The structures have been evaluated as containing very significant amounts of gas locked in a challenging deep and hot environment requiring hydraulic fracture stimulation. Recently, horizontal well trials started taking place in two of the structures aiming for testing efficiency of this type of completion and further evaluation of formation deliverability. Successful completion of horizontal laterals would open new horizons in this challenging environment. Achieving this goal is not possible without thorough evaluation of reservoir conditions followed by completion and stimulation. Horizontal well performance in a tight gas reservoir is largely controlled by the number of hydraulic fractures placed along the lateral and their spacing and conductivity. Designing a reservoir access strategy might not be a trivial task, either, when the well trajectory intersects several productive vertical layers and the reservoir properties are changing laterally. Manual selection of intervals and perforations could be susceptible to mistakes and may be perceived as subjective at times, while also being time and effort consuming. The workflow based on reservoir quality (RQ) and completion quality (CQ) developed in North America for unconventional resources for optimizing completion decisions brings engineering to this process for stage and cluster selection in horizontal sections. This project applies the same reservoir-centric RQ/CQ workflow integrating all available data and creating specific criteria and cutoffs applicable to a specific tight gas field in the Sultanate of Oman.
Briner, Andreas P (Petroleum Development Oman) | Moiseyenkov, Alexey Vladimirovich (Shell) | Prioul, Romain (Schlumberger) | Abbas, Safdar (Schlumberger - Doll Research) | Nadezhdin, Sergey Valentinovich (Schlumberger) | Gurmen, Mehmet Nihat (Schlumberger IPM-SPM)
A recent series of tight gas discoveries in the Amin formation of the greater Fahud area represents some of the most exciting exploration success of this decade in the Sultanate of Oman. The structures have been evaluated as containing very significant amounts of gas locked in a challenging deep and hot environment requiring hydraulic fracture stimulation. Since their discoveries, the two primary challenges have been difficult breakdown of the formation and limited proppant placement during stimulation attempts. The early experience in the exploration and appraisal campaigns from 2009 to 2014 has led to fracture designs with conservative proppant amounts that could limit the full potential of the field. Several geomechanical studies have been commissioned in the past to guide completion strategies in well placement, perforation, and fracture stimulation design. The objectives of this study were to model hydraulic fracture initiation and breakdown in the three Amin zones (upper, middle, and lower) to provide some theoretical understanding of the impact of the different parameters on the observed field breakdown pressures. In agreement with field observations, the model showed that lowering the viscosity of the pad has a major impact in lowering the breakdown pressures. Consequently, current best practices include formation breakdown and hydraulic fracture propagation with low-viscosity fluids followed by proppant placement with high-viscosity fluids. When applied to tight gas formations in the Sultanate of Oman, the hybrid fracturing evolves from conventional designs for the purpose of successful fracture initiation, while still placing a successful job.
Although famous for its abundant oil fields, generations of production in the Middle East is putting sharper focus on ultimate recovery from these fields.
The issue is particularly pressing for Oman. Output in the country’s maturing oil fields peaked in the 1990s and Petroleum Development Oman (PDO), the national oil company, spearheaded the implementation of enhanced oil recovery (EOR) techniques with its first trials in the late 1980s.
For Oman, EOR remains a major strategic option in its challenge to increase recovery and to meet long-term production requirements. Substantial efforts have been directed at investigating cost-effective ways in which production levels from existing fields can both be sustained and increased.
Oman’s first EOR program was completed in 1989 and led to progress in experience gained and reduction in technical and cost uncertainties. Oman has seen considerable investment in a range of EOR technologies to produce heavy oil, and a host of other countries in the Middle East and India have been encouraged by Oman’s success. Between 2001 and 2007, Oman’s oil production fell by 27%, but by 2009, due mostly to EOR projects, oil production had increased by 17%.
In a region where national oil companies essentially control all the hydrocarbon resources, Oman’s partnership between national and international oil companies stands out, also because it has been an important driving force behind the country’s EOR rollout. The growth in use of EOR techniques has increased the cost of Oman’s oil production but also has boosted output by 180,000 BOPD to 200,000 BOPD. Total Oman production is 940,000 BOPD. “In comparison with primary oil extraction, which sometimes costs only USD 4-5 per barrel, EOR techniques come at an expense of USD 10-12 per barrel,” said Salim bin Nasser Al-Aufi, undersecretary of the Ministry of Oil and Gas in Oman.
The EOR techniques that Oman has used include chemical EOR as well as thermal and miscible gas injection. The choice of EOR technology is based on the reservoir depth and oil viscosity.
PDO, which produces more than 80% of Oman’s oil production, commissioned its first EOR project in 2004, and expects that EOR will contribute to 25% of total liquids production by 2020. “We have had to move into a significant program of EOR technologies. We are the only company in the world that has thermal, miscible, and polymer chemical-injection recovery mechanisms within the same concession, all of which are in full-scale implementation,” said Raoul Restucci, managing director of PDO.
Naturally Fractured Reservoirs (NFR) contain a significant amount of remaining petroleum reserves and are now being considered for water-alternating-gas (WAG) flooding as secondary or tertiary recovery. Reservoir simulation of WAG is very challenging even in non-fractured reservoirs because a proper set of saturation functions that describe the underlying physics is vitally important but associated with high uncertainty. For NFRs, another challenge is the upscaling of recovery processes, particularly the fracture-matrix transfer during three-phase flow, to the reservoir scale using dual-porosity or dual-permeability models.
In this work, we approach a solution to this challenge by building models at various scales, starting from pore-scale to an intermediate scale then to the reservoir scale. We show how pore-network modelling and fine grid modelling where the fractures and matrix are represented explicitly can be used to increase the accuracy of numerical simulations at the field-scale in order to predict recoveries for NFR during WAG. We study the sensitivity to WAG design parameters as well as the impact of matrix wettability on recovery. We also compare the fine grid model with an equivalent dual-porosity model.
Simulation at an intermediate scale showed at least 10% absolute change in recovery due to the choice of the empirical three-phase relative permeability model. In fine grid simulation with physically consistent pore-network derived three-phase relative permeability and capillary pressure, injected water and gas are predicted to displace each other, leaving oil behind, therefore reducing WAG efficiency. For this case, empirical models over-estimate recovery by 25%. Classical dual-porosity model over-estimates recovery during the early WAG cycles, and fails to adequately match recovery of the fine grid simulation.
Our multi-scale simulation approach identifies important factors and uncertainties when considering WAG flooding in NFR. It provides a methodology through which WAG recovery can be estimated using available technology while preserving the pore-scale physics for three-phase flow, which are crucial to making reliable forecasts at the reservoir scale.
Naturally Fractured Reservoirs (NFR) comprise highly complex heterogeneities as their most conductive features, the fractures, have the least storage capacity; and vice-versa, their least conductive features, the rock matrix, has high storage but normally only a small contribution to flow. This renders the design of enhanced oil recovery (EOR) schemes difficult because of early water and/or gas breakthrough and the overall recovery factor of NFR is often very low. This has been shown in numerous case studies (e.g. Davidson and Snowdon, 1978; Denoyelle et al., 1988; van Golf-Racht, 1982; Panda et al., 2009). Nonetheless, a significant portion of the world's remaining petroleum resources are located in NFR, including super giant fields in the Middle East. Hence, a detailed understanding of the recovery processes involved in extracting the hydrocarbons from NFR using EOR techniques is the key to increase the ultimate recovery for such reservoirs.
Continuous water injection is a well established secondary recovery method which aims primarily to displace the oil and maintain the reservoir pressure. In NFR, oil is first displaced in the fractures but held back in the rock matrix. Oil displacement from the rock matrix by injected water is capillary dominated and hugely dependent on the wettability of the rock. Water flooding has been implemented with various degrees of success in NFR (Brownscombe and Dyes, 1952, Thomas et al., 1987). For unfavourable, i.e. mixed- to oil-wet, matrix wettability, however, water flooding can be ineffective. This was sometimes shown by field experience. Secondary recovery plans were hence changed from water to gas injection (O'Neill, 1988, van Dijkum and Walker, 1991).
Waterflooding has been the most popular post-primary production approach for improving oil recovery. In fractured reservoirs with large structural relief, gas injection can produce much of the post-waterflood remaining oil by gravity drainage. Oil recovery by gas-invoked gravity drainage in waterflooded reservoirs is known as the double displacement process (DDP). One major reason, among many, is that the three-phase relative permeability residual oil saturation endpoint is generally smaller than the residual oil saturation endpoint for the water-oil displacement.
Field data indicate that the DDP has been successful in single-porosity sandstone formations. Intuitively, one can expect that DDP should produce similar results in reservoirs with ample intercommoned vertical fractures, which is the objective of this work. With the aid of tests on tight reservoir cores from a major Middle East carbonate reservoir, this study focuses on evaluating the DDP in fractured carbonate reservoirs where the wettability ranges from neutral to oil-wet conditions. The scope of the study includes: (1) assessment of the DDP experimentally in fractured cores using a high-speed centrifuge, (2) simulating the experiments numerically, and (3) upscaling laboratory results to field applications.
Results from water-oil gravity drainage tests followed by gas-oil gravity drainage in fractured and unfractured cores are presented. We also show numerical simulation results of matching the experiments using both transfer function and 2-D numerical simulation, and how results from our study can be used in field applications.
Typical waterflood oil recovery from 0.1-md to 2-md fractured carbonate cores has been noted to be around 38% of the initial oil in place while incremental additional oil recovery for gas-oil gravity drainage is nearly as much as the recovery from water.