|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Al Habsi, Yumna (Schlumberger) | Anbari, Ali (Petroleum Development Oman) | Al Yaarubi, Azzan (Schlumberger) | Leech, Richard (Schlumberger) | Al Bimani, Sumaiya (Schlumberger) | Choudhury, Suryyendu (Shell)
Abstract Perseverance in quantifying the remaining hydrocarbon saturation, in cased boreholes, remains critical to take business decisions and prioritize operations in brownfield waterflood development. Challenges with cased hole saturation evaluation acquired in certain complex completions such as those completed in multiple casing-tubing strings, slotted-liners and sand-screens require advanced tool technology. Pulsed Neutron Logging (PNL) is one such technology used successfully to analyze behind casing saturation evaluation. The PNL device provide accurate and precise measurement, and with robust processing and environmental compensation corrections, the saturation uncertainty can be delineated. A robust cased hole hydrocarbon saturation and uncertainty estimation enables informed decision making and value driven workover prioritization. The new generation PNL tool features a high-output electronic neutron source and four signal detectors. Near and far Gamma Ray (GR) detectors are made of Cerium-doped Lanthanum Bromide (LaBr3: Ce) featuring high-count rate efficiency and high-spectral resolution (largely insensitive to temperatures variations). A deep-reading GR detector made of Yttrium Aluminum Perovskite (YAP) in combination with a compact fast neutron monitor placed adjacent to the neutron source, enables a new measurement of the fast neutron cross section (FNXS) which provides sensitivity to gas-filled porosity. A newly devised pulsing scheme allows simultaneous measurement in both time and energy domains. The time-domain measurement aid in analyzing the self-compensated capture cross section (SIGM), neutron porosity (TPHI), and FNXS. The energy-domain measurement provides a detailed insight for high-precision mineralogy, total organic carbon (TOC), and carbon/oxygen ratio (COR). The high statistical precision energy-domain capture and inelastic spectral yield data are interpreted using an oxide-closure model which when combined with an extensive tool characterization database provide lithology and saturation measurements compensated for wellbore and completion contributions. This paper shares the advanced features of the new multi-detector PNL tool run in a horizontal well targeting the aeolian Mahwis Formation, consisting of unconsolidated sands and the glacial Al Khlata Formation (Porosity ranges 0.25 – 0.29 p.u.). In this case-study, the well was completed with uncemented sand screens and production tubing to mitigate sanding related risk. The absence of cement behind casing and the presence of screens adds considerable complexity to the saturation analysis. Furthermore, due to low water salinity (∼7000 ppm NaCl equivalent), saturation must be determined using carbon spectroscopy-based techniques - namely the COR and TOC. Logging conventional PNL tools in horizontal wells can lead to lengthy acquisition times, thus adding considerable operational complexity and cost. With the new PNL technology advancements, the time required to acquire high-quality data can be halved. Saturation outputs computed independently from COR and TOC methods showed close agreement and allowed for the direct compensation of changes in borehole oil hold-up without which the computed saturation would have been overestimated. The remaining oil saturation estimation behind cased hole and uncertainty quantification enable a proper understanding of well production performance and uncovered further opportunities. In addition, decision based strategic data acquisition to quantify remaining hydrocarbon saturation enables unlocking growth and ‘no further action’ (NFA) opportunities, impacting production recovery and meeting bottom-line targets in brownfield assets.
Abstract As the oil and gas industry has been investigating the challenges in identifying reservoir compartmentalization and interpreting the negative influences it generates, diverse disciplines within the oil and gas industry have presented beneficial approaches to inspect and reduce the challenges found while exploring and appraising oil fields. despite the various pieces of literature that have been published in this field stating that reservoir compartments are either structurally or stratigraphically in origin depending on the depositional facies or fault geometry. This study presents, geochemical data from twenty oil samples which are used to investigate horizontal and vertical compartmentalization of the Jawdah Field, which is located in the south of Oman. The data were intended to identify the causes of the segmentation using fluid properties. The results from each oil sample are integrated with carbon isotopes, whole-oil gas chromatography, saturates, aromatics, resins and asphaltenes (SARA) analysis and biomarkers in order to detect different variations in fluid composition that may be lead to better understanding of reservoir compartmentalization. Based on these four analyses, the research findings indicate that Jawdah oils are derived from a single source rock (Huqf oils). The identification of the Huqf source rock was based on the similarities between pristane and phytane peaks from the whole-oil gas chromatography data and the carbon isotopes for the Jawdah oils and from the Grantham (1988) paper. However, the API gravities in Jawdah field varied ranging from light to moderately heavy oil (20-33 API), indicating a possibility of other geological factors affected the alteration of the crude oil. Therefore, these oils were further characterized by interpreting the level of maturation and biodegradation ratios using biomarker signatures. This combination of methods has provided a more advanced method of investigating and interpreting compartmentalized reservoirs and it will lead to enhancing recovery. It was found that the Gharif and Al Khlata reservoir units are not in communication, potentially impacting well design, and field development planning.
Abstract Water flooding has been widely used as secondary oil recovery method in the clastic reservoirs in PDO. Field development plan of this field requires water injection under matrix injection conditions. The field consists of stacked Gharif sand stone reservoirs with variable degree of depletion. Increased injection volumes at economical rate, could induce hydraulic fracturing where it is very important to manage fracture growth and reducing risk for out of zone injection. The success of water flood development depends on an optimal injection pressure, which requires knowledge of formation fracture pressures and geomechanical rock properties. Efficient geomechanical analysis and workflow integrating data from well tests, field performance, water injection history and monitoring data was implemented for this study to provide guidance on optimum water injection pressure. Field stress tests, such as Leak off Tests (LOT) and micro fracs were analyzed to derive the fracture pressures. Gharif formation in these stacked reservoir formations have been significantly depleted hence a reduction in fracture pressure was required to be assessed. Depletion stress path coefficient, which is the ratio of change of fracture pressure and reservoir depletion, was derived based on historic field data. Data from well tests, field water injection performance was used for Modified Hall plot analysis and other diagnostic plots to provide better insight on active water injection operating conditions (fracture, matrix and plugging). Finally, for injector operating above the fracture pressure, Produced Water Re-Injection (PWRI) model was used to simulate expected fracture dimensions, and quantify the out of zone injection risk. Results of this study indicate that the decrease in fracture pressure in Gharif formations is about 60% of the change in pore pressure (depletion). Qualitative and quantitative analyses were able to characterize the operating injection conditions (matrix vs. fractured) for active injectors. Interpreted fracture pressure from Gharif water injector diagnostic plots demonstrates good alignment with the measured fracture pressure from field tests. The results reveal that most of the water injector wells, particularly in the depleted formations are operating above fracturing pressure. Predicted fracture dimensions form the PWRI model calibrates well with the field monitoring data. Outcome of this study provided fracture pressure estimate for Gharif formation with depletion and provide guidance on optimum water injection pressure to improve waterflood management. Stress path chart provide continuous improvement and quick decision for water flood operation. Results quantified the induced fracturing to mitigate the risk of out of zone injection and/or loss of sweep efficiency. Additionally, the results provide continuous critical input for fracture gradient for drilling and cement design for wells through depleted stacked reservoirs in other field within Gharif formation.
Abstract This paper reviews the fluid contact analysis of the Marmul Gharif South Rim (MM GSR) heavy oil field in the South of the Sultanate of Oman. The field is highly compartmentalized by several faults into 17 blocks in total with a large variation in well density within those blocks. The reservoir in this field is the shaly-sand Gharif formation, in which the Middle and Lower Gharif are separated from each other by either a paleosol or competent shale. The hydrocarbon in these sands has an observed viscosity variation as a function of height above free water level (HAFWL) due to biodegradation. This variable viscosity has been observed in a large number of oil samples with higher viscosity close to the oil-water contact (OWC). The sands tend to be vertically discontinuous in the wells, so that direct observation of the OWC on logs is very rare, causing most well logs to yield only water up to (WUT) or oil down to (ODT). Accurate pressure gradients are difficult to obtain due to the low density contrast of heavy oil against the fresh formation water. Consequently, the OWC is not readily identified in certain blocks. This has resulted in either over-estimating oil volumes when substituting WUT or under-estimating volumes when substituting ODT in specific blocks of the field. In addition these cases also result in a lack of reliable constraints for estimating high and low case oil contacts. Methods, Procedures, Process A viscosity based approach was used to overcome gaps in the fluid contacts data-set and provide essential information for future field development. The approach utilizes the viscosity data in each block to determine representative base case contact along with shallow and deep cases. The results of this analysis were confirmed by production data and are consistant with the ODTs from horizontal wells. The resulting fluid contact is then used as an input to the saturation height function which is used later as an input to calculate in-place volumes. Results, Observations, Conclusions Viscosity based contact provides a more robust fluid contact definition in areas where traditional methods resulted in data gaps. The paper presents a detailed methodology of this approach. Novel/Additive Information The results of this work are an essential component of optimizing the understanding of the fluid contact in the field, which helps to develop the field efficiently by drilling the oil producers and water injectors in more optimum locations.
Abstract The presence of bitumen is an obvious risk for reservoir development. Pore-filling bitumen degrades reservoir quality. Sweetspotting, discriminating between producible oil and gas and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and the optimal development planning. However it is in most cases impossible to make such differentiation using conventional logs. It is well known that the Nuclear Magnetic Resonance (NMR) log provides an opportunity to identify the presence of reservoir bitumen in oil bearing reservoirs. The zones containing bitumen within oil and water reservoirs are characterized by lower NMR porosity estimates when compared to porosity from the density and neutron tools. But in gas reservoirs, bitumen identification from NMR porosity deficit is not a common industry practice. The porosity deficit could be related not only to the presence of bitumen, but also to the presence of gas in the pore space. The case studies include tight gas reservoirs in Miqrat and Middle Gharif formations, both located in the Sultanate of Oman. Well tests showed gas rates lower than expected, accompanied by low mobility and sometimes water production from intervals with relatively good porosity and saturation calculated from logs. Besides, bitumen was identified from core. A new methodology was developed which can differentiate between residual gas and bitumen presence based on Density, Neutron and NMR logs in conjunction with resistivity. One of the pre-requisites is that the reservoir lithology must be known. The remaining gas saturation is quantified from Density-Neutron separation. If we know the Hydrogen index (HI) of gas, the NMR porosity deficit can be compensated for residual gas effect. Bitumen saturation can be quantified from the difference of total porosity and NMR compensated porosity. The methodology was tested on two tight gas reservoirs of the Sultanate of Oman. Core analysis, production data, and total organic carbon (TOC) derived from pulsed neutron logs were used to verify the results of the suggested methodology. The comparison shows that the methodology can be used for semi-qualitative identification of bitumen. It was also observed that the bitumen distribution varies across the field, and overall the majority of reservoir hydrocarbons are moveable. Recommendations on the workflow for static and dynamic modeling were provided. The suggested novel approach of bitumen identification in gas bearing reservoirs is relatively simple. It provides fit for purpose results for gas bearing reservoirs including tight gas which in turn can be used for more accurate estimation of gas volumes and optimizing development planning.
Alsop, D. B. (Petroleum Development) | Pentland, C.. (Petroleum Development) | Hamed, W.. (Petroleum Development) | Al Ghulam, J.. (Petroleum Development) | Al Ma‘Mary, T. S. (Petroleum Development) | Svec, R.. (Petroleum Development) | Al Kiyumi, A.. (Petroleum Development) | Al Daoudi, Y.. (Petroleum Development)
Abstract 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.
Al-Yaarubi, A. H. (Schlumberger) | Rose, D. A. (Schlumberger) | Zhou, T.. (Schlumberger) | Gonzalez, G.. (Schlumberger) | Lombardi, P. A. (Schlumberger) | Kechichian, J.. (Petroleum Development) | Ross, R. R. (Petroleum Development) | Lukmanov, R. B. (Petroleum Development) | Guntupalli, S.. (Petroleum Development) | Reda, A.. (Petroleum Development) | Al Ani, K. M. (Petroleum Development) | Al Shoaibi, S. S. (Petroleum Development) | Al-Habsi, Y. R. (Schlumberger) | Grover, R.. (Schlumberger)
Abstract This paper presents field applications of a new slim pulsed neutron logging tool (PNL) in the Sultanate of Oman. In the spectroscopy mode, the tool provides high-resolution capture and inelastic spectroscopy measurements with significantly improved accuracy and precision over the previous-generation tools. In the gas, sigma, and hydrogen index (GSH) mode, the tool provides self-compensated sigma and neutron porosity measurements for a wide range of environmental conditions, including gas-filled boreholes. This mode also introduces the fast neutron cross section (FNXS) measurement, which is sensitive to variations in gas-filled porosity and is insensitive to variations in liquid- filled porosity. The answers from this tool are valuable for formation evaluation and reservoir monitoring in conditions where existing technologies are limited. Five case studies of various field applications demonstrate the benefits from the tool's elevated specifications in comparison with existing technology. The first case study addressed three fluid phases in a carbonate oil reservoir undergoing water and gas cap expansion. The second case study evaluated the gas-bearing potential of the Gharif formation. Evaluation of the Middle Gharif formation is particularly challenging due to its complex mineralogy and the co-existence of bitumen and gas. The third case study targeted the tight gas reservoirs in the Barik and Miqrat formations. The challenging environment posed by the combination of low permeability and a gas-filled borehole made this well a very good candidate to explore the new tool's capability for providing accurate self-compensated sigma and hydrogen index logs with the required precision. The fourth case study was conducted in an observation well that is completed with plastic-based casing to monitor an enhanced oil recovery pilot. Achieving optimal saturation accuracy was the primary objective. The fifth case study targeted organic-rich carbonate mudstone in the Natih formation. The primary objective was the determination of total organic carbon (TOC) behind casing. Openhole logs, production data, and core analysis were used to verify the results of the new slim PNL tool. The traditional applications of PNL spectroscopy tools, such as reservoir monitoring and analysis behind casing, benefit greatly from the tool's elevated precision, accuracy, and detailed mineralogy description. In addition to this, integrating carbon-oxygen and the FNXS measurements enables the evaluation of multiple phases, such as those typical in thermal or gas-injection-based developments.
Abstract In Petroleum Development Oman (PDO), a seismic driven 3D Close the Loop workflow has been successfully applied for the first time to the Tibr asset. The business objective was to delineate channel sands with challenging rock properties at a relatively deep target by better predicting the distribution of sands and shales within the Upper Gharif and Al Khlata reservoir sequences. As a result, we were able to reduce subsurface uncertainties leading to improved reserve estimates. 3D Close the Loop workflows allow for better predictions of layer thickness, reservoir properties and velocity away from the wellbore by optimal integration of seismic amplitudes with all other reservoir data. A pre-existing static reservoir model describing reservoir properties through geo-statistical algorithms served as main input. Rock and fluid property models were derived from existing well data. By relating reservoir properties such as net-to-gross, porosity and hydrocarbon saturation to acoustic properties, the 3D models were converted to a synthetic seismic volume, which could then be compared to measured seismic data. In the final stochastic inversion, reservoir properties were updated until synthetic and seismic data matched within an acceptable error range defined by the signal to noise ratio.
Abstract A quantitative interpretation (QI) study has successfully predicted the distribution of sands and shales in the Upper Gharif. This was indisputably confirmed by three wells drilled after completion of the QI study. By integrating a range from low to high "tech" QI technologies, a workflow in a land environment could be developed that enables us to delineate channel sands with challenging rock properties at a fairly deep target. Integral part of this workflow comprehends the alignment of the petrophysical data, seismic data and production data in a consistent manner. Then, joining the maps from RMS amplitudes, spectral decomposition and seismic facies classification with products from the AVO inversion allowed us to construct a confidence map, which assigns areas with different probabilities to encounter these channel sands. Building further on this QI success, the first 3D Close-the-Loop (3DCtL) project in Petroleum Development Oman (PDO) ever was initiated. This methodology strives to obtain an accurate as possible static reservoir model, which is consistent with all available subsurface data. The workflow consists of two main steps. Firstly, a rock property model is derived from well data and then the reservoir properties (net-to-gross, porosity and hydrocarbon saturation) in the static model are used to generate synthetic 3D seismic data and compared with the measured surface seismic data. In case of disagreement, the second phase involves a stochastic seismic inversion which updates the reservoir properties and makes them consistent with the measured seismic data. While running through this workflow, a number of deficiencies in the static reservoir model came to surface. Besides improvement in the thicknesses of the layers away from well control and in the velocity model used for time-depth conversion, the main enhancements from the stochastic inversion amounts to more realistic net-to-gross and porosity estimates and improved insight in the sand distribution in the Al Khlata reservoir. Ultimately, the subsurface uncertainties are considerably reduced and result into improved reserve estimates. The significance for PDO is that although this technology is well established in most major oil companies, this is the first time it has been successfully applied on a PDO seismic data volume.
Choudhuri, Biswajit (Petroleum Development Oman) | Kalbani, Ali (Petroleum Development Oman) | Cherukupalli, Pradeep Kumar (Petroleum Development Oman) | Ravula, Chakravarthi (Petroleum Development Oman) | Hashmi, Khalid (Petroleum Development Oman) | Jaspers, Henri (Petroleum Development Oman)
Summary In viscous oil reservoirs, Polymer flooding is often used to improve oil recovery either after a short period of waterflooding or as a tertiary recovery process following extensive period of waterflood. After six years of water flooding in a major reservoir in Sultanate of Oman having viscous oil (90cp), a field development plan was developed to implement polymer flooding in this reservoir with anticipated incremental oil recovery of around 10% over and above that of waterflood. Necessary facilities were constructed, injection and production wells were drilled, completed, converted and the polymer flood project was initiated and ongoing since the last three years through 27 polymer injectors. By implementing proactive Well and Reservoir Management (WRM) strategies, the actual oil recoveries have been better than predicted levels so far. It is demonstrated here that proactive well and reservoir management through proper well and reservoir surveillance and dynamic adjustment of injection and production rates play a very important role in improving the performance of polymer floods as in waterfloods. Well and Reservoir Management (WRM) principles in case of a polymer flood are similar to that of high mobility ratio waterfloods with some additional aspects that are specific to a polymer flood scenario. Polymer chemical costs, its higher viscosity and non Newtonian fluid flow behavior all create unique conditions that are nonexistent in normal waterfloods. This, in turn, dictates the strategies and methods employed to optimize polymer flood performance. This paper details successful implementation of proactive WRM strategy that has played a key role in sustaining production from this polymer flood field to date. It describes the pattern management processes to optimize pattern wise polymer injection and oil recoveries, conformance control measures implemented to increase sweep and oil recovery, innovative surveillance techniques to monitor fracture growth in polymer injection wells and for evaluation and optimization of production/injection profiles. Production wells and facilities issues arising from polymer breakthrough are being addressed to mitigate any adverse effects.