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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.
AL Isaee, Omar (Petroleum Development Oman) | Chavez Florez, Juan (Petroleum Development Oman) | Ali, Nada (Schlumberger) | AL Ghatrifi, Rawan (Petroleum Development Oman) | Al-Yaqoubi, Mazin (Petroleum Development Oman) | AL Abri, Ahmed (Petroleum Development Oman) | AL Hinai, Mohamed (Petroleum Development Oman)
In Oman, the unique geological properties of the reservoirs require different fracture strategies and technology deployment to make them commercially viable. Highly deviated wells, with multiple hydraulic fractures, have been identified as key technology enabler for the development of tight gas accumulations in Oman. The main objective of this study is to generate a 3D petrophysical and geomechanical view of the reservoir, to have a better understating of Hydraulic Fracturing for Horizontal and Highly Deviated Wells
The comprehensive amount of data captured during the initial implementation phase of highly deviated wells covering reservoir characterization, fracture geomechanics as well as production logs in combination with the existent data captured in vertical wells, proves to be complex to analyze due to the volume of information and the multi variable nature associated with fracture and inflow predictions. A methodology was required where correlations and tendencies were identifiable at structural level, covering all target gas accumulations using all the static and dynamic captured data. The definition of a 3D Grid Visualization Block (3D-GVB) was introduced where all the captured parameters were distributed for analysis and interpretation.
As a result of the appraisal and initial field development with vertical wells, it was possible to identify tight accumulations that will require dedicated highly deviated wells for its development. The initial phase of the implementation of highly deviated wells proves to be challenging, as the observed heterogeneities on geomechanical and petrophysical properties across the target gas accumulations, combined with differential depletion and the wells orientation to generate transverse fractures, creates a complex environment for fracture initiation and propagation, impacting not only fracture deployment but inflow deliverability of this wells. This paper will describe how the methodology uses a cycle of data analysis and interpretation to identify tendencies, that will lead to correlation and new algorithms that are retrofitted on the 3D-GVB platform, leading to optimization of well positioning at structural level, drilling and completion of this highly deviated wells.
It will be described how this methodology is used for well positioning at structural level, to define well architectures oriented to enhance not only drilling, but also hydraulic fracturing and hydrocarbon deliverability on highly deviated wells.
The paper discusses a petrophysical evaluation method for complex tight gas formations in a mature and partially depleted gas condensate field in Oman, allowing a full petrophyscial evaluation as well as geomechanical modeling from a source-less petrophysical dataset, thus reducing operational data acquisition risk in partially depleted reservoirs without compromising on hydraulic fracturing design. The developed methodology includes the volume of shale estimation from correlation with Poisson's ratio for the feldspathic rich tight formation.
Heidorn, Rodrigo (Petroleum Development Oman) | Salem, Hisham (Petroleum Development Oman) | Shuaili, Salim (Petroleum Development Oman) | Khattak, Ali (Petroleum Development Oman) | Pentland, Christopher (Petroleum Development Oman)
The Eastern Flank part of the South Oman Salt Basin of the Sultanate of Oman is an important area for Oman's overall oil production. The fields are largely controlled by deep seated reactivated Neoproterozoic faults and halokinesis of the Infra-Cambrian Ara Group responsible for rich varieties of complex structural styles which have direct impact on field performance and development. The fidelity of newer seismic, the ever increasing information from wells and better integration of various data sets of different disciplines allow new insights into the unlocking of remaining hydrocarbons within existing fields and within near field exploration opportunities.
The South Oman Salt Basin is subdivided into four NE-trending salt-related structural domains based on the type of salt withdrawal minibasins present. The Eastern Flank is located within structural domain I. Domain I represents the area where evaporites have been initially present, but have been subsequently removed by salt-dissolution and salt evacuation. The dominant structure style is the ‘mini turtle back structure', which shows a diverse structural architecture and is systematically classified based on structure- and fault architecture. Domain II is the zone of the large inverted salt withdrawal minibasin or turtle back structure which is located at the salt edge of the basin with evaporite presence in the subsurface. The structural style of a large turtle back structure shows complexities within the core of the structure and within the surrounding rim related to inversion and truncation of the Carboniferous and Permian reservoirs. This is reflected by the various development scenarios related to simple and complex cores as well as to simple and complex rims. Fault compartmentalization has a strong impact on field performance within domain I and II, thus several types of faults are established based on fault architecture and location within the structure. The systematic classification of structural styles and faults allow the establishment of analogues, which are in particular valuable for seismically poorly imaged areas. A new tool captures and centralizes the structural data, as well as a large range of other data sets within the production and geoscience environment from over 60 fields with the aim to make more consistent and better as well as quicker decisions related to field development planning.
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.
The Barik formation is a tight low-permeability conventional gas reservoir in the Sultanate of Oman comprising of a series of interbedded sandstones and shales. To achieve an efficient and economic development of this formation, the wells require the application of massive hydraulic fracturing operations, in order to achieve the required surface area and connectivity for production delivery.
Hydraulic fracturing operations often involve the use of a wide range of chemical components and the industry has understood for some time that chemical reactions take place both during and after fracture treatments have been performed. Post fracture treatment a wide range of differing chemical effects can take place and this may continue for some time during the extensive flowback and clean-up period. Such chemistries can result in a range of differing effects, including unplanned scaling tendencies, corrosional behaviour and can even influence aspects such as hydrate control. Such effects can also have an adverse impact on the well itself, the surface manifolding/valves, gathering system and production facilities and need to be well appreciated in order to remove issues.
During the early Appraisal of the Barik formation, in Block 61 in the Sultanate of Oman, H2S had been observed during the post-frac well-test operations. However, the Barik reservoir within the Khazzan field, was believed to be sweet and not reflect a measurable H2S; a characteristic that had been confirmed by performing pre-frac openhole sampling. As had been determined with fracturing operations elsewhere, it was surmised that the frac operations themselves where the potential source of the H2S. Potential causes for this included thermal decomposition of fluid chemistry as well as inadvertent contamination of original source water used for the feed fluid. It had been observed/measured, that the magnitude of H2S reduced with time and was directly related to fracturing fluid clean-up. After extensive investigation the evidence suggested that the root-cause was a combination of the presence of a hardy Sulphate Reducing Bacteria (SRB) species along with the presence of a thiosuplhate feedstock in the frac fluid.
This paper will present a full, robust and coherent analysis of the presence of H2S, the rigorous steps that were followed to identify the root-causes and the identification of potential sources/causes. The paper will present the preventive measures that have been taken and their impact on the overall temporary levels of H2S that have been seen in the operations since. The paper will go on to recommend that for future operations, particularly start-up areas, as transitory levels of H2S might not be identified, not because H2S is not there but rather that there is typically no apparatus nor sufficiently accurate surveillance in place on everyday operations to precisely identify such material.
ABSTRACT: Many salt bodies contains rock inclusions (or stringers) with various deformation patterns. The internal complexity of salt structures is strongly impacted by the deformations of the inclusions such as displacement, folding, fracture and thrusting. In combination with adaptive remeshing, a finite element model has been built for downbuilding simulation. The standard model setup is constrained by observations from Zechstein salt Basin and the South Oman Salt Basin. Different from the previous research showing the fracture, overtrusting of brittle inclusion during downbuilding process, a sensitivity study has been performed on the numerical model of deformation and displacement of ductile rock bodies, including various viscosity contrasts between salt and stringer. The results of study show the ductile stringer has extension and folding. The results of study also show that the viscosity contrasts between salt and stringer strongly influence the internal structure of salt basin.
Salt tectonics is strongly related to hydrocarbon reservoirs in sedimentary basins worldwide and salt sections often include encased rock inclusions such as rafts, floaters or stringers. The study of stringers has also contributed to our understanding of the internal deformation mechanisms in salt diapirs (Talbot and Jackson 1987, 1989; Talbot and Weinberg, 1992; Koyi 2001; Chemia et al., 2008). The studies of the internal structure of salt are also typically related to the risk of drilling because of short and long term salt creep behavior (Jumelet, 1982; Van Eekelen et al., 1983; Breunese and Schroot, 2004; Urai et al., 2004, 2008; Strozyk, 2017).
Figure 1 shows cross section of Zechstein salt in Groningen area and isoclinal folding (or Z3 stringer folds) are included in salt section (Bornemann, 1991; Behlau and Mingerzahn, 2001). Moreover, seismic observations (typically 2D to 3D in salt mines) include boudins and folds together with shear zones (Bornemann, 1991; Geluk, 1995; Burliga, 1996; Taylor, 1998; Behlau and Mingerzahn, 2001). The folds have curved, open-to-isoclinal fold axes, and boudins from millimeter (Schléder et al., 2008) to kilometer scale (Burliga, 1996) are common. Richter-Bernburg (1980) further describes several examples of fold structures with amplitudes over half the height of the salt structures. An observation of 3D reflection seismic data shows the internal structure of Zechstein salt including the large-scale, complex folding and fault (Van Gent, 2011). In Figure 2, during salt tectonics, the internal structure continues to fold and it will ultimately brecciate or stretch into boudins if salt flow continues (Strozyk, 2017).
Ferrero, M. Boya (Petroleum Development Oman) | Dhahli, A. (Petroleum Development Oman) | Unal, E. (Petroleum Development Oman) | Bazalgette, L. (Petroleum Development Oman) | Wahabi, A. (Petroleum Development Oman) | Holst, M. (Petroleum Development Oman) | Doan, H. (Petroleum Development Oman)
The development of thin oil rims in carbonate reservoirs requires good understanding of structural setting, reservoir architecture and transition zone saturations. Fields that have a tectonic and/or geochemical history after initial charge are likely to challenge standard assumptions of fluid distribution, contacts and saturationdepth relationships. This paper is a case study illustrating downflank field extension opportunities in an oil rim, related to post-charge tectonics affecting fluid distribution and contacts. The structure of this article encompasses four different aspects: 1. begins by explaining the geological concepts that are being postulated for downflank hydrocarbon potential, 2. proposes the alternative methodology of concept-driven analysis for log data interpretation, 3. explains in detail the methodology applied to existing field data for reservoir architecture and fluid fill description, 4. summarises the outcome of the appraisal well with respect to alternative concepts. The workflows that justified the placement of appraisal wells downflank followed the philosophy of concept-driven analysis where data is used to eliminate hypothesis rather than averaged into one a-priori assumption or average fitting equations. The placement of the pilot appraisal well (at a depth interval and location where previous models predicted water-fill) has been enabled by the identification of stratigraphic rock types, regional variability of fracture intensity and the prediction of tilted contacts. The results of an appraisal well drilled in 2017 confirm the alternative concepts proposed from concept-driven analysis of legacy log data: - Flank reservoir thickness improvement due to post-deposition crestal erosion of best facies.
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.