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. This methodology was used in deep tight fields in Oman for more than 3 years in both vertical and highly deviated wells greatly reducing the risk, logging cost and complexity of operations.
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. 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.
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).
Cobanoglu, M. (PDO, Petroleum Development Oman) | Soleimani, A. (PDO, Petroleum Development Oman) | Mourad, A. (PDO, Petroleum Development Oman) | Sulaimi, A. (PDO, Petroleum Development Oman) | Deori, M. (PDO, Petroleum Development Oman) | Noirot, J. C. (PDO, Petroleum Development Oman)
The deep SR gas field was discovered in 1991, with rich gas-condensate in the Barik and lean gas in the Miqrat reservoir. The field has been on depletion production since 1999 from the Barik reservoir and started commingled production from Barik and Miqrat reservoirs in 2001. Areally the field is split into three tectonically and dynamically separated blocks namely the SR Main to the North, the SR Graben and the SR South.
The field is currently producing with 189 active wells out of 214 drilled wells. The field is currently utilizing a second stage compression where the suction pressure is 13 bars. The field development relies on the 2010 Field Development Plan (FDP) concept that proposed using fracced vertical wells and commingled production from the two producing units, Barik and Miqrat.
An integrated subsurface-surface study was conducted in 2015-2016 with the objective to deliver a new FDP that aimed at the redefinition of the gas and condensate forecasts for the next 10 years through a focused development of the tight gas units and delivery of further identified opportunities in the SR field.
This study covered a new static model that included a complete new petrophysical interpretation of available data with updated saturations and contact evaluations, an updated structural interpretation and new field property modeling, a new full field dynamic model and an evaluation of various further compression and infill options. A new technology plan to address critical development challenges was also developed.
This paper covers:
The challenges faced in the development of the SR gas condensate field
The dynamic modeling challenges and workflow
The evaluation of further infill well options (i.e. highly deviated horizontal and vertical commingled wells)
The feasibility of a full field vertical well development conducted to estimate the optimum number of wells required for such a development
The evaluation and optimization of further compression options
The identification and evaluation of additional contingent resource (i.e. extension of facility life, etc…) to further improve ultimate recovery
The identification of critical issues/challenges, the screening of different technology solutions as well as the development of a technology staircase to address those challenges
The economical evaluation of development options
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 saturation-depth 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: begins by explaining the geological concepts that are being postulated for downflank hydrocarbon potential, proposes the alternative methodology of concept-driven analysis for log data interpretation, explains in detail the methodology applied to existing field data for reservoir architecture and fluid fill description, summarises the outcome of the appraisal well with respect to alternative concepts.
begins by explaining the geological concepts that are being postulated for downflank hydrocarbon potential,
proposes the alternative methodology of concept-driven analysis for log data interpretation,
explains in detail the methodology applied to existing field data for reservoir architecture and fluid fill description,
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. Fracture density reduction towards the northern flank of the dome structure. Tilted oil contacts deepening towards the flank and related to paleo-charge. Relatively dry oil production from deeper depth intervals with low oil saturation due to transition zone water mobility.
Flank reservoir thickness improvement due to post-deposition crestal erosion of best facies.
Fracture density reduction towards the northern flank of the dome structure.
Tilted oil contacts deepening towards the flank and related to paleo-charge.
Relatively dry oil production from deeper depth intervals with low oil saturation due to transition zone water mobility.
The drive mechanism and development options for the field should be investigated further.
Richard, Pascal (Shell Global Solutions International B. V.) | Zampetti, Valentina (Shell Global Solutions International B. V.) | Volery, Chadia (Shell Global Solutions International B. V.) | Gesbert, Stephane (Shell Global Solutions International B. V.) | Krayenbuehl, Thomas (Shell Global Solutions International B. V.) | Spaak, Michael (Shell Global Solutions International B. V.) | Murzin, Shamil (Shell Global Solutions International B. V.) | Neves, Fernando (ADNOC) | Hosani, Sabah Al (ADNOC)
ADNOC and Shell are currently joining efforts to rejuvenate the exploration portfolio of Abu Dhabi. A country-wide integrated petroleum system study is being carried out to identify new play concepts and opportunities. One of the foundations of this study is the understanding of the structural evolution and its impact on prospectivity.
A structural evolution model has been developed using 2D and 3D seismic data and the country has been divided into structural domains. The extent and quality of the seismic dataset provided a unique opportunity to investigate the country wide structural evolution. Special care has been taken to generate seismic attribute volumes that enhance sedimentary features and fault visualization. This allowed the detailed assessment of fault displacement. In addition, mapping of the edge of carbonate platforms through time at the country scale allowed the identification of long wavelength tilts of the Arabian plate in Abu Dhabi. These observations have been linked to the regional phases of deformations. The most important phases of deformation that affected the trap formation are the Jurassic rifting, the Late Cretaceous transtension, and mid Tertiary compression.
The country has been divided into specific structural domains using existing structural features. These structural elements comprise NS and NW-SE striking basement features, forced folds associated with basement features, drape folds associated with salt domes, and NW-SE and NNW-SSE conjugate sets of transtensional faults zones associated with pop-up structures.
With the help of sandbox experiment analogue models as well as field analogues from Oman, we propose that the Late Cretaceous transtensional faults are decoupled from basement and do not root into any deep basement faults. We also propose a series of conceptual 3D fracture diagrams per structural domain.
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.
Openhole multistage (OHMS) completion systems have been available for nearly 20 years. Their introduction was primarily linked to improved operational efficiency, achievable through the elimination of redundant operations, costs, and time from the existing application of plug-and-perf (P&P) solutions. However, increased understanding with time has demonstrated that the most effective applications of the approach are those that offer better connection within the reservoir. Examples of such applications include delivery of fracturing within extended reach wells, application to naturally fractured formations, and use of the OHMS systems in offshore or logistically challenged areas.
The use of an OHMS system has a number of potential advantages for certain applications, not least of which is preservation of the uncemented annulus with extensive direct reservoir access within the completion. One of the major advantages of this geometry is that there is an unparalleled and flawless wellbore-to-reservoir communication in place, immediately prior to fracturing. In hard-rock, high-stress-ratio cased-cemented scenarios, where tortuosity and near-wellbore friction can dominate, an ability to avoid such issues in the first place is an advantage. This is particularly true in those horizontal wells drilled and completed in complex stress regimes. In these cases, a complex connection resulting from perforating can often be detrimental to creation of desired fracture width, making proppant placement challenging and thereby reducing the effective fracture conductivity.
Within the Khazzan field, in the Sultanate of Oman, such a complex tectonically impacted stress-state exists in the formations of interest, combined with an ancient hard-rock environment exhibiting a wide variance in effective permeability. Early multifractured cased-cemented horizontal well simmediately demonstrated complex fracture-to-wellbore communication behaviour, which was addressed in a number of ways. One of these approaches included plans for deployment of the OHMS as a potential technique to ensure a smoother and simplerfracture-to-wellbore interface.
This paper will fully describe the experience of the first OHMS completion deployed in the Khazzan field including details on the fracture design, operational execution, surveillance, post-fracture cleanup, and productivity. The paper will particularly address those aspects related to near-wellbore tortuosity, fracture connectivity, proppant placement, and evidence of connection quality. The paper will assess this completion approach alongside previously applied techniques and report on the potential of the approach for more widespread deployment in resolving fracture complexity.