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Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Belhaij, Azmi (Saudi Metal Coating Company) | Alkamil, Ethar H. K. (University of Basrah)
Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.
Available headroom (difference between dewpoint and reservoir pressure) in liquid rich gas reservoirs and drawdown scenario affect the condensate dropout near the wellbore. Although effects of the liquid dropout are well understood in radial system, addition of hydraulic fracture in the low perm reservoirs complicates the saturation profile in reservoirs. Massive hydraulic fracturing in vertical tight sand wells adds effective surface area to flow and can mathematically be considered as placing long horizontal wells to reduce overall well draw downs. This work shows that this additional contact with matrix rock, therefore, can play a major impact in mitigating or postponing the impact of skin caused by condensate banking. This paper presents a real case of Pressure Transient Analysis (PTA) for hydraulically fractured wells in unconventional gas-condensate reservoirs. Detailed analysis of PTA will be discussed and addressed using analytical and high-resolution numerical models in which compositional multiphase flow is considered. The numerical model is history matched and fine-tuned on pre-frac and post-frac well test results. The impact of hydraulic fracture half-length, fracture conductivity and matrix relative permeability on condensate banking effects will be addressed via a numerical simulation study for various scenarios. The paper will demonstrate the value of hydraulic fracturing in reducing condensate baking effect on well productivity and, by inference, the impact on the long-term economic value of gas-condensate wells.
Field K1 as part of AA Tight Gas Cluster features significant variability in the fluid properties, concluded through PVT, well test as well as geochemical measurements. Following an extensive data acquisition program that was conducted at the beginning of the project, a multi-disciplinary review and integration of data was carried out in order to adequately characterize the fluid distribution across the field.
Several analyses were employed to understand the characterization of the fluid distribution through geochemistry analysis, compositional gradient analysis and lateral fluid investigation.
Gas samples and mud gases were collected during drilling and analyzed for gross composition and stable carbon isotope for geochemical analysis purposes. Condensates were collected and analyzed for gross composition, sulfur content and isotopic analyses. Analyses of both fluid types aimed at gathering reliable information in terms of source type and thermal maturity of gases. The large number of data points from high resolution sampling of mud gases allowed for a more confident examination of charge history and communication of the Upper Amin Formation across the cluster of fields.
The gas and condensate samples were taken after well completion for further PVT analysis. Gas composition, temperature, fraction of liquid drop-out and measured Dew Points suggested complex reservoir fluid and genetically different behavior with a contrasted fluid signature across Field K1. Plotting the fluid composition, phase envelopes, as well as Dew Point gradient supported application of a complex-fluid modeling together with segmentation.
The understanding of the fluid behavior is important for the reservoir description as well as the overall development plan of Field K1. The impact on the development plan includes: missing condensate recovery opportunity, on-plot and off-plot facility design, overall gas and condensate recovery factor per well, and the sequence of development.
This new analysis resulted in an upward update in resource volume estimation of Field K1. Well placement and drilling sequence optimization were derived as the positive outcome of this exercise.
The Barik formation is a low-permeability conventional tight-gas reservoir, in Block 61 in the Sultanate of Oman, comprised of a series of interbedded sandstone and mudstone (shale) layers. To achieve the most efficient and economic development of this formation sequence, the wells require the application of massive hydraulic fracturing. Such an approach was developed and deployed during the Appraisal stage of the programme and a considerable effort was placed in ensuring that the fracture height was contiguous, resulting in an effective drainage across all layers of the Barik formation. This approach was then encapsulated in the Full Field Development (FFD) planning Basis of Design (BoD) and was established as the approach to be taken throughout FFD.
Until the field development was well underway, a single fracture treatment had proven sufficient to stimulate the entire Barik reservoir. However, as the development moved into the Southern area of the field, a substantial thickening of the Barik sequence was encountered and with this change successful complete vertical propped fracture coverage became much more challenging to achieve in an effective and repeatable manner. This paper demonstrates the approaches that were subsequently taken with the fracture design, the fracturing fluid selection and the fracture perforation strategy to address this issue and restore the achievement of complete fracture/formation coverage.
Throughout the paper a number of examples will be presented that demonstrate the issues and effects that arose with the thickening of the Barik formation. The paper will then go on to examine how these effects were identified, what surveillance was used and the various characteristics that were displayed and how they were inferred. It will examine how the various issues were addressed, what changes were made to the fracturing strategy and demonstrate, through direct results, the outcomes that were subsequently achieved.
This paper will focus on some of the principal issues that can arise when moving a developing fracture BoD in a laminated sequence into a more thickly developed environment with more extensive height and bulkier sands. The paper will provide a number of detailed examples of the issues themselves, and describe the detrimental and impactful effects that they may have on fracture coverage and hence well productivity and EUR. Additionally, the paper will describe the approaches that can be used in order to successfully address these effects. The paper will clearly demonstrate that when such considerations are taken into account that a successful suite of outcomes can be achieved.
Smit, Jeroen (Petroleum Development Oman) | Adawi, Anwar (Petroleum Development Oman) | Hinai, Faisal (Petroleum Development Oman) | Khayari, Mustafa (Petroleum Development Oman) | Abri, Mohammed (Petroleum Development Oman) | Kiyumi, Hassan (Petroleum Development Oman) | Nakireddi, Naidu (Petroleum Development Oman) | Yousef, Hamada (Petroleum Development Oman)
This paper discusses the journey of drilling excellence in Khulud field, one of the most challenging fields in Sultanate of Oman and the Middle East. It highlights the changes in well design, drilling optimization and efficiency improvement which resulted in significant cost and time improvement in the development campaign.
Amin formation is the target reservoir, at about 5,000 meters in depth, with some of the hardest rock formations in the area in excess of 50 Ksi compressive strength. The reservoir pressure gradient is approximately 18 kPa/m (1.84 SG) and static downhole temperature is around 178 °C.
An integrated approach was taken to address the challenges as the field transitions from appraisal stage to development. This involved the selective deployment of technology along with improved operations, and implementation of several initiatives which resulted in a significant improvement in well durations and cost in excess of 40% within a year. The well design was altered from a five casing string design in the exploration and appraisal phase to a three string slim design with liner top completion. Additionally, a cemented completion design was introduced and executed successfully, involving the implementation of a specially designed degradable packer fluid to reduce the burst loads on the casing in the frac and production phase of the wells. The bit selection and drive type was changed from turbine drilling with an impreg bit to motor drilling with a PDC bit application specially designed for the field and its challenging conditions. The change led to major improvement in ROP (Rate of Penetration) and accordingly reduced time to drill the final 8 3/8" hole section. Furthermore, the implementation of Lean practices and following the well delivery process stages played a crucial role in aligning all parties involved together. A Performance Improvement Plan (PIP) was developed and implemented to capture the different initiatives in well design and operational excellence and was used as a vehicle for continuous improvement.
The results show significant reduction in well cost and time by 40 % compared to well cost before implementing these changes. Recent wells have beaten the Best Composite Time (BCT) set in the field and reduced the overall duration from 260 days in the exploration stage to 55 days in the recent wells delivered in 2017.
The cemented completion with degradable mud was a first time application in PDO, requiring in-house development and testing. The PDC bit used in recent wells was specifically designed for Khulud to replace the impreg bit and enhance ROP.
Marhoon, Nadhal Al (Petroleum Development Oman LLC) | Masroori, Haitham AL (Petroleum Development Oman LLC) | Abdul-Majid, Imran (Petroleum Development Oman LLC) | Ajayi, Ayotunde (Petroleum Development Oman LLC) | Sandoval, Daniel (Petroleum Development Oman LLC) | Khan, Raees Ahmed (AAPG, Petroleum Development Oman LLC) | Qasmi, Liali Al (Petroleum Development Oman LLC)
The Tight Gas Reservoir (TGR) top structure is well defined in seismic data and can be interpreted across the entire area of North Oman. It is being identified as an extremely tight, disconnected, low porosity, low permeability and High Pressure – High Temperature (HPHT) reservoir, and thus presents unique challenges to harness its full production potential. Therefore, to optimise the subsurface location and ensure placing a successful well, the following approaches were implemented.
Firstly, full 3D geological model was generated to reproduce the reservoir heterogeneities and sedimentological behaviour of the TGR. Secondly, sweet spot identification techniques were used due to the heterogeneity nature of TGR properties in order to locate the optimum subsurface location. Lastly, a well completion strategy centred on hydraulically fractured cased-hole wells with immediate production to mitigate formation damage was implemented. This is achieved via abrasive jetting and thermal conductivity techniques to induce micro fractures that vastly enhanced the fracture efficiency, with velocity strings combined with depletion compression.
Furthermore, the characterization and simulation efforts are aimed to test the longevity of the wells in an Early Production System (EPS) to evaluate the optimal well count and spacing for the full Final Development Plan (FDP). Also, the interference between the wells in this tight formation has been studied. Data gathering activities encompasses formation evaluation logs, core analysis data and well test data.
The surface development concept is based on staged field development, with long term testing as the first milestone. EPS have been selected to provide long term production data gathering opportunity for assessing the reservoir and well performance behaviour in order to aid in defining the FDP.
This paper will highlight the success of unlocking tight, unconnected gas and describe methodologies applied to aid fully integrated subsurface loop development. Reservoir characterization, model creation and simulation challenges linked with the appraisal results will also be discussed.
A large, strategically important tight gas project in the Sultanate of Oman progressed over 5 years on an accelerated path from exploration to the development stage. Collaboration between operator and service provider helped advance the deployment of technology that made this acceleration possible. Poor initial success in both hydraulic fracturing treatment placement and hydrocarbon productivity along with limited resources with ever-expanding work scope were the main challenges faced in the first 2 years of exploration. To address these challenges, an integrated approach to the project was taken. Technology trials and the selective deployment of technology along with improved operations gave flexibility to this new efficiency model. Close collaboration with the service provider allowed smoother and faster progress. Collaboration included joint technology mapping exercises, team visits to North American locations of the operator and the service provider with the goal of knowledge sharing, faster technology transfer, and the secondment of a senior engineer from the service provider as a full-time production technologist to the operators' subsurface team. The effective execution of strategy and implementation of various technologies resulted in an increase in the success rate of fracture placement and zonal evaluation from the initially low 50% to 100%. The integration of several disciplines was critical to achieving this goal. Technologies deployed in the project comprised of rock and core mechanical tests, such as reservoir coring, openhole stress testing, sonic measurements, continuous unconfined compressive strength measurements, abrasive perforating, various fracturing treatment designs, and several geomechanical studies targeting different aspects of fracture initiation. An additional focus was on the assessment of fracture geometry using radioactive tracers, advanced sonic logging, geomechanical evaluation coupled with geological mapping, microseismic monitoring, and cutting-edge fracture design methodology in both vertical and horizontal wells. The collaborative efforts led to evaluation of similarities and differences between North American and international unconventional projects and suggested techniques and best practices that can be applied in the tight gas project in the Sultanate of Oman. This project has been deemed one of the first commercially successful gas deliveries in the Middle East from a tight gas reservoir. Technologies, methods, and strategies developed for this large tight gas project and tested in the field will contribute to improving the success rate on similar projects around the world.
Alsop, D. B. (Petroleum Development) | Pentland, C. (Petroleum Development) | Hamed, W. (Petroleum Development) | Al Ghulam, J. (Petroleum Development) | Al Ma‘Mary, T. S. H. (Petroleum Development) | Svec, R. (Petroleum Development) | Al Kiyumi, A. (Petroleum Development) | Al Daoudi, Y. (Petroleum Development)
The Gharif Formation is one of the most prolific oil and gas producing clastic reservoirs in the Sultanate of Oman with production spanning five decades and thousands of wells. The depositional environment for the Gharif varies both vertically as well as spatially across Oman making identification of appropriate field analogues challenging. A thematic study of the Gharif Formation over the last few years has added new insights into the impact of these geologically complex reservoirs on connectivity and field development options. The objectives of the development catalogue is to utilize the geological, petrophysical and reservoir engineering knowledge and data to support the decision making process.
The Gharif is divided into three main units with the depositional environments ranging from fluvio-deltaic, shoreface, tidal flats, semi-arid and humid tropical fluvial systems. Each environment has its own respective reservoir characteristics such as reservoir properties, body geometry, vertical and lateral connectivity and net to gross. These environments vary between units as well as regionally across Oman. Standardization of core facies and well picks with the application of sequence stratigraphy has enabled regional palaeogeography maps to be created at flow unit level. Production is often co-mingled with nine possible reservoir combinations and fluids range from heavy oil (<20 °API) to gas. Development areas have been identified based on regional palaeogeography maps, diagenetic trends and fluid properties. For each area and unit, an assessment of the rock and fluid properties has been undertaken and key uncertainties are identified and captured in a matrix. A review of development decisions and approaches resulted in an understanding of how optimal field development varies throughout the Gharif; the key development decisions were captured in a decision matrix.
The distillation and analysis of the extensive Gharif dataset has resulted in specific tools and workflows that are available to aid better, and faster, decision making in Gharif field developments. Technical databases put the appropriate quality controlled data at the field developer's finger tips while development workflows utilizing uncertainty and decision matrices empower teams in their decision making process. We envisage field development studies benefiting from the consistent application of identified best practices resulting in significant multi-month time savings.
This work has shown how formation specific data, covering a wide geographical area, can be integrated and analysed to quickly assess subsurface uncertainties and identify appropriate analogues. This in turn enables development teams to make better and faster decisions on development options. This approach will now be replicated for other formations in Oman.
Briner, Andreas (PDO) | Nadezdhin, Sergey (Schlumberger) | El Gihani, Mahmoud (Schlumberger) | Al-Wadhahi, Taimur (Schlumberger) | El-Taha, Yasin Charles (PDO) | Harrasi, Othman (PDO) | Kelkar, Shrihari (Schlumberger)
In the last 3 years, Petroleum Development Oman (PDO) went from failure to success with microseismic monitoring of hydraulic fractures in deep, high-pressure/high-temperature (HP/HT) horizontal wells. The most recent operations were performed in the conditions of the highest complexity to date.
The hydraulic fracture monitoring (HFM) was performed in the 69° deviated section of a horizontal well with the geophones conducted on wireline. The perforation shots for velocity model calibration were performed through casing with no cement behind (a feature of the treatment well completion), which has not previously been documented in publication. A new generation of microseismic geophone shuttles was used on the stinger with two knuckle joints to enable passing through the high-dogleg sections of the well.
The geophones spent up to 12 hours downhole in one run with no signs of failure. The sensor array was successfully deployed on the first attempt in all runs in the highly deviated well section. Four fracturing stages were monitored, yielding hundreds of good-quality microseismic events. This provided enough data to evaluate the fracture geometry and complexity, symmetry of fracture wings, diversion efficiency of swell packers, and the number of fractures initiated in the same stage and their propagation. All this provided input for meaningful comparison of the openhole completion with previously completed cased holes. This data will guide future field development, well count, well spacing and will enhance the fracturing design of any future wells.
Briner, Andreas (PDO) | Nadezhdin, Sergey (Schlumberger) | Tessari, Sergio (PDO) | Smit, Jeroen (PDO) | Busaidi, Yazeed (PDO) | Abri, Mohammed (PDO) | Mitri, Joelle (Schlumberger) | Shalaby, Ehab (Schlumberger)
This case study describes the deployment of logging tools on tractor in challenging wellbore conditions in a tight gas field in the Sultanate of Oman. Challenging conditions are defined by a high static temperature of 175°C; high static reservoir pressure of 72 MPa; a long, 5700-m wellbore; openhole configuration; and horizontal well profile. One of the conventional ways of deploying the caliper measurement in horizontal wells is through drillpipe conveyance. Deployment through coiled tubing conveyance is another option; however, this was not available owing to extensive logistical requirements and the operation's complexity. A newly developed openhole tractor designed for the well's extreme conditions was used to efficiently convey the logging tools. Features that enabled successful tool conveyance included the highest tractor force available in the industry, 6-drive tandem wheels, real-time adjustment of the radial force to the tractor arms, and active traction control for improved maneuverability. Calipers were successfully conveyed with the wireline tractor in the 800-m horizontal section of the 5000-m-deep well. The logging job took only 12 hours versus the traditional 60 hours required to convey the same tools on drillpipe. In addition, the tractor conveyance minimized the risks associated with operating at high temperature because it significantly reduced the time of exposure of tools to extreme high temperatures approaching their maximum temperature ratings, hence ensuring top performance and reliability. The fivefold time reduction also helped with the well economics and minimized the overall operational risks associated with the logging operation. The recorded caliper data enabled proper evaluation of the hole conditions for selecting the best location for setting the swellable packers.