Little is known about the nature and origin of microcrystalline quartz in sandstone reservoirs or mudstone reservoirs. We have utilized advanced analytical capabilities to improve our understanding of controls on microcrystalline quartz development in several examples where porosity is preserved in deeply buried sandstone reservoirs to understand the development in siliceous mudstones.
In this study, several advanced analytical techniques were used to evaluate the crystallographic and compositional controls on the formation of microcrystalline quartz. SEM/Cathodoluminescence (CL) imaging confirms that quartz overgrowths have a complex growth history. Previous workers (Kraishan et al. 2000) suggested that CL patterns in quartz cement are largely due to trace elements rather than defects and that aluminum varies consistently between each cement phase. Electron Backscatter Diffraction (EBSD) combined with Wavelength Dispersive Spectrometry (WDS) confirms that the complex banding visible in CL is not due to changes in crystallographic orientation but more likely variations in quartz composition associated with changes in pore fluid composition and/or reservoir conditions. Secondary Ion Mass Spectrometry (SIMS) analysis provides maps of ultra-trace element distribution that confirm that trace amounts of iron, manganese, and titanium can be used as proxies for defect density and temperature. Additionally, SIMS analysis provides oxygen isotope data providing insight into the initial reservoir conditions and temperature of formation of microcrystalline quartz in several formations.
Microcrystalline quartz in the form of replacement, micropore, and overgrowth cements is present in the Wolfcamp A in the southern Delaware Basin. The amount of cementation has an effect on the reservoir quality and appears to have an impact on the petrophysical properties. The siliceous mudstones are comprised predominantly of biogenic silica (sponge spicules, radiolarians, which are the silica sources for the authigenic microcrystalline quartz), detrital grains (quartz and feldspars), pyrite framboids, and organic matter.
Integrating the results from these advanced analytical techniques has helped us develop our understanding of the processes controlling the formation of quartz cement and improved our ability to reconstruct the reservoir diagenetic history of quartz growth leading to a proposed model for predicting porosity preservation in deep, hot sandstone reservoirs and the formation of microcrystalline quartz in siliceous mudstones. This is the first research to report on spatially resolved isotopic analysis of silica cements integrated into a petrographic framework and a proposed mechanism for microcrystalline quartz growth.
Multistage hydraulically fractured horizontal well completions have come a long way in the last two decades. Much of this advancement can be attributed to the shale gas revolution, from which numerous transformational tools, techniques, and concepts have led to the efficient development of ultralow-permeability resources on a massive scale. Part of this achievement has been through a widespread trial and error approach, with the higher risk/failure tolerance that is a trademark of the statistical nature of the North American unconventional resource business. However, careful consideration must be taken not to blindly apply these techniques in more permeable tight gas formations, which often cover an extensive range of permeability. Inappropriate application can compromise the effectiveness of the hydraulic fracture treatment and impair long-term well productivity.
Khazzan is a tight to low-end conventional gas field in the Sultanate of Oman, with low porosity and permeability in comparison to conventional formations. The target formations comprise extremely hard, highly stressed rocks at high temperature. The development strategy included vertical wells with massive hydraulic fracture treatments and multistage fractured horizontal wells. The former has been largely successful in the higher-permeability areas, and the economic transition from vertical to horizontal well development, based on rock quality, is continuously evolving. Compared to the rapid learning curve achieved through the more than 80 vertical wells drilled to date, fewer horizontal wells have been drilled, and, as a result, the understanding is still relatively immature.
The paper outlines the technical and operational journey experienced in horizontal wells, to prepare the wellbore and ensure a suitable frac/well connection for successful fracturing and well testing. The paper will describe how the intervention tools and practices have varied between the Barik and Amin formations; depending upon rock quality, frac treatment type, drive to maximize operational efficiency and availability of local resources. The differential application of these techniques, that result in measurable under-flush versus in contrast to the typical North American unconventional practice of defined but limited overflush (e.g., pump-down plug-and-perf will be described). Justification for these different approaches in two very different formations will be demonstrated, including supporting evidence of their relative value.
The obstacles that have been faced, overcome and are still ongoing with this campaign highlight the importance of several critical factors: including multi-disciplinary integration and planning, wellbore construction impacts, contractor performance and tool reliability. Although practices for shale and very low permeability sands are well documented, this paper provides a suite of case histories and operational results for horizontal well intervention techniques used in high-pressure and high-temperature sandstones that are in the very specialized transition zone between conventional and unconventional.
The mainly Cenomanian Shilaif formation of Abu Dhabi (UAE) is currently explored and appraised for its shale oil and shale gas potential. The objective is to assess the hydrocarbons resources, the spatial variability of rock and fluid properties as well as highlighting sweet-spots.
The exploration efforts started in 2014, conducting some multidisciplinary regional depositional and petroleum system studies complemented with exploration wells and the acquisition of comprehensive suites of logs, cores and pressured (sidewall) cores.
The Shilaif formation was deposited in a deeper water intrashelf basin and is time equivalent to the adjacent shallow water higher energy Mishrif formation. Non-eroded Shilaif thicknesses vary from 500 to 900 ft from deep basin to slope respectively. The formation can be subdivided into 3-4 composite sequences each with separate source rocks and clean tight carbonates.
The present day structural configuration is inherited from two related regional compressional events; a) a NW-SE compression responsible for the anticline/syncline, lasting from Late Cenomanian to Early Eocene was created by India's continental drift, b) the late Cretaceous (starting in Turonian) emplacement of the Semail ophiolite from NE direction responsible for loading the continental plate and resulting in the creation of a large scale foreland basin. Reactivation of this NE compression occurred during Late Tertiary.
The resulting structuration created two synclines in the south of Abu Dhabi with maximum maturity of 1.1 Vr (TR 0.65). The foreland basin towards the North East has maturity values reaching the dry gas window. The continuous present day stress from a NE direction combined with high overpressures has a strong geomechanical impact with hmin close to overburden in synclinal areas.
This study aims to present the unconventional resource potential of the Late Albian to Early Turonian basinal sequences in Abu Dhabi.
Insights into the local and regional stratigraphic framework as well as structural controls of the depot-centers are presented.
The objective of this work is to characterize the fault system and its impact on Mishrif reservoir capacity in the West Quran oil field. Determination and modelling of these faults are crucial to evaluate and understanding fluid flow of both oil and water injection in terms of distribution and the movement. In addition to define the structure away from the well control and understanding the evolution of West Qurna arch over geologic time.
In order to achieve the aim of the work and the structural analysis, a step wise approach was undertaken. Primarily, intensive seismic interpretation and building of structure maps were carried out across the high resolution of 3D-seismic survey with focusing on the main producing Mishrif reservoir of the field. Also, seismic attributes volumes provided a good information about the distribution and geometry of faults in Mishrif reservoir. The next step, it constructs 3-D fault model which will be later merged into the developed 3D geological model. West Qurna/1 oil field situated within the Zubair Subzone, and it is structurally a part of large anticline towards the north. The observation of seismically derived faults near Mishrif reservoir indicated en-echelon faults which refer to strike-slip tectonics along with extensional faults. The statistic of Mishrif interval faulting indicates a big number faults striking north-south along western wedge of anticline. The seismic interpretation, in combination with seismic attributes volumes, deliver a valuable structural framework which in turns used to build a better geological model.
In this paper, the work demonstrates a better understanding for the perspectives on the seismic characterization of the structural framework in the Mishrif reservoir, and also for similar heterogeneous carbonate reservoirs. Further, this work will ultimately lead to improve reservoir management practises in terms of production performance and water flooding plan.
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.
Monitoring and reevaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals. LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations. LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition.
Busaidi, Adil Zahran Al (Schlumberger) | Hawy, Ahmed El (Schlumberger) | Omara, Ahmed (Schlumberger) | Lawati, Ali Baqir Al (Schlumberger) | Vasquez Bautista, Ramiro Oswaldo (Schlumberger) | Awadalla, Muhannad (Schlumberger) | Al Ghaithi, Ghaida Abdullah Salim (Schlumberger) | Chibani, Zied (Petroleum Development Oman) | Al Jamaei, Suroor (Petroleum Development Oman)
Torsional vibration (also known as stick and slip) is a major contributor to equipment failures and severe damage when drilling the 6 1/8-in. lateral limestone Shuaiba reservoir section in PDO North Oil fields. This paper examines multiple factors that can affect the severity of stick and slip and measures their actual impact. These factors include bit/bottomhole assembly (BHA) design and formation/mud properties. The effect of a software plugin to an automated drilling system that was designed to mitigate the effects of stick and slip was also examined.
Initially, drilling dynamics data available for the lateral Shuaiba reservoir were analyzed to evaluate the levels of torsional vibration. Several proposed design changes to reduce the torsional vibration were then modeled separately using finite element analysis (FEA) to predict their dynamic behavior. Trials were conducted, and the impact of independently changing each factor in the overall torsional vibration was assessed. Data were collected from over 40 horizontal wells drilled in the same reservoir. In each set of trials, identical drilling conditions were maintained while changing a single factor.
The analyzed legacy set of well data showed high levels of torsional vibration (stick and slip) in the lateral section for different fields that share nearly the same reservoir characteristics and bit/BHA design. Using a similar formation profile, the FEA modeling results suggested that stiffening the drillstring and using heavier sets of PDC bits would greatly reduce the torsional vibrations while maintaining a good rate of penetration. When these changes were applied, actual data were analyzed to measure the improvement. Additionally, the analysis found that specific formation characteristics such as formation density highly contribute the severity of torsional vibration.
Modeling also suggested that applying higher torque to the bit reduces its RPM fluctuations and allows for lower surface parameters. This, in return, reduces the amplitude of the torsional vibration. Over eight trials were analyzed, and significant reductions in both the measured torsional vibrations levels and equipment failures and damages were seen.
Finally, the effect of utilizing a software plugin to an automated drilling system to mitigate stick and slip when drilling the 6.125-in. lateral limestone reservoir was examined. Like the other proposed solutions, the remaining factors were kept constant.
The paper offers a rare case study specific to lateral limestones reservoirs, where interbedded layers are a common contributor to the severity of torsional vibrations. The results and conclusions are based on downhole high-resolution data to calibrate finite element models to provide fit-for-purpose solutions. The results eliminate much of the theoretical explanations about root causes of torsional vibrations in limestone reservoirs.
Sayapov, Ernest (Petroleum Development Oman) | Nunez, Alvaro Javier (Petroleum Development Oman) | Al Salmi, Masoud (Petroleum Development Oman) | Al Farei, Ibrahim (Petroleum Development Oman) | Gheilani, Hamdan (Petroleum Development Oman) | Benchekor, Ahmed (Petroleum Development Oman) | Al-Shanfari, Abdul Aziz (Petroleum Development Oman)
Multistage frac completion (MFC) has been playing a significant role in modern oilfield industry being one of the key tools making development of low permeable formations economical. Commonly, it is applied in horizontal wells that are drilled to compensate for reduced drainage radius of these wells due to a lack of formation conductivity. This technique is evolving, there are quite a few inventions introduced every year that make MFC easier, more economical and that allow the operators to control and precisely evaluate both the treatment itself and performance of the created fractures. However, due to its nature and initial focus on horizontal wells, it did not become very popular in vertical wells. One of the reasons for it is its limited formation access since the sleeves that are providing the access are short and cannot cover the entire net pay. What historically more common in vertical wells are either conventional "plug and perf" approach or its modifications, whereas intervals are perforated with either coiled tubing and sand-blasting perforation or wireline guns, while isolation of the zones is achieved by setting frac plugs, sand plugs or frac packers depending on pumping conduits. In Petroleum Development Oman, some of these vertical wells were stimulated via multistage frac completion.
In central part of the Sultanate of Oman, a deep tight gas field is developed using hydraulic fracture stimulation technique since the formation conductivity is low and the near wellbore damage after drilling is making it even worse. Normally, between 6 and 13 frac intervals are stimulated in each well. Majority of wells are completed vertically with pay zones separated with strong shale layers that restrict fracture height development. Since plug & perf has been the main technique used in this field, there are multiple well interventions during hydraulic fracture operations that consume time, money and delay the well delivery. Moreover, the depletion of the field and its main productive zones make well intervention activities much more challenging whereas the risks of getting coiled tubing string or even wireline tools stuck in wellbore are high due to immediate losses faced after opening those low pressurized zones having as low as 8,000 KPa formation pressure, which can be 5-7 times less than hydrostatic pressures in the wellbore depending on depths and fluid s used. At the same time, with downhole temperatures ranging from 135 to 150 deg C and fracturing pressures reaching around 145,000 KPa bottomhole (~21,000 psi), differential pressures across the target zones can reach enormous levels of 15,000-20,000psi. Conditions in general become very risky, making it extremely difficult to source the right tools and equipment from what is available on the market. Another challenge associated with depletion of this field is an effective deliquification of the wells after stimulation treatments to allow them to effectively get rid of frac fluids and be able to produce gas to surface.
By deploying multistage frac completion with the objective of producing, enhancing and cost/time savings, the effectiveness of the fracturing operations was expected to increase. Multistage frac completion allows the frac operation to be continuously performed without the need to conduct well interventions such as running/setting frac plugs, perforating, milling and clean out between intervals. If needed so, the intervention activities can be completed after frac operations. Equipment selection and completion design were performed based on well conditions, market availabilities, operational parameters and composition of the produced gas. However, this technique is associated with its specific challenges that require attention and tailored solutions. The main challenge in deployment of this system in vertical wells is the accurate positioning of the sleeves. The shale layers between the pay zones could be as narrow as 5 m or less and a small pay zone can be easily missed. Besides, deployment and cementing operations are equally essential because of water zones embedded in between the pays.
This paper is discussing the recognized benefits and lessons learned from utilization of multistage frac completion in vertical deep (around 5000 m) depleted tight gas wells covering the completion and hydraulic fracturing stimulation operations. This technique has industry proven cost & time reduction and efficiency gain, as well as faster well cleanup and reduced HSE exposure contributing to better gas recovery, improvement in operator's performance and energy delivery to the country; it was expected to demonstrate a step change in the efficiency compared to conventional approach to the field development.
The Khazzan field is being developed currently and includes multiple gas-bearing formations. The primary development reservoir is the Barik sandstone, which is characterized by permeabilities on the order of 0.1 to 1 md. An additional reservoir under development is the Amin formation, which lies deeper than the Barik and is perhaps more unconventional in nature, with estimated permeabilities an order of magnitude lower than the Barik formation. Both reservoirs require hydraulic fracturing to produce at economically attractive rates and, as such, carry the same sort of challenges to reservoir understanding inherent to all unconventional plays. This was recognized in advance of the appraisal program, and an approach was taken to address these challenges in a more-holistic fashion, encompassing a full suite of data gathering, including surveillance and well testing. One of the key tools used was DFIT along with associated ACA of the decline to determine reservoir properties. During the appraisal phase, significant rigor was aimed at ensuring high-quality data would be recorded and that an appropriate amount of time would be allocated to monitoring pressure declines to enable valid interpretations. This resulted in the ability to draw a good correlation between data gathered from the ACA operations and data collected from post-fracturing well-test data.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191437, “ACA Practical Considerations: When Is It Accurate and How Should It Be Used To Improve Reservoir Stimulation,” by O.A. Ishteiwy, SPE, M. Jaboob, and G. Turk, BP; S. Dwi-Kurniadi, SPE, Schlumberger; A. Al-Shueili, SPE, A. Al-Manji, and P. Smith, BP, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed.
The use of diagnostic fracture injection tests (DFITs) for prefracture investigation has become routine in the oil field, particularly for understanding reservoir properties and subsequently optimizing hydraulic-fracture design. A key component of an effective DFIT is an after-closure analysis (ACA) to assess the transmissibility of the formation and allow for effective design. This paper describes a DFIT-analysis program and the suitability of the results from ACAs for use in hydraulic-fracture design.
The Khazzan field is being developed currently and includes multiple gas-bearing formations. The primary development reservoir is the Barik sandstone, which is characterized by permeabilities on the order of 0.1 to 1 md. An additional reservoir under development is the Amin formation, which lies deeper than the Barik and is perhaps more unconventional in nature, with estimated permeabilities an order of magnitude lower than the Barik formation. Both reservoirs require hydraulic fracturing to produce at economically attractive rates and, as such, carry the same sort of challenges to reservoir understanding inherent to all unconventional plays. This was recognized in advance of the appraisal program, and an approach was taken to address these challenges in a more-holistic fashion, encompassing a full suite of data gathering, including surveillance and well testing.
One of the key tools used was DFIT along with associated ACA of the decline to determine reservoir properties. During the appraisal phase, significant rigor was aimed at ensuring high-quality data would be recorded and that an appropriate amount of time would be allocated to monitoring pressure declines to enable valid interpretations. This resulted in the ability to draw a good correlation between data gathered from the ACA operations and data collected from post-fracturing well-test data.
Methods and Process Stimulation and Testing Sequence. The approach taken to stimulate and test the wells in Khazzan was to use a dedicated well-test unit. The overall sequence was as follows: