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BP is developing the Khazzan and Ghazeer fields of Block 61 in the Sultanate of Oman. The development includes three Cambro-Ordovician tight gas sand reservoirs which require hydraulic fracturing for commercial production rates. There are challenges with depth and high temperature for the open hole logging environment, with a restrictive inner diameter and residual proppant creating challenges for the cased hole logging environment. Additionally, there are cost challenges on all data acquisition including coring, downhole gauges, sampling, proppant tracers and many other forms of surveillance.
This paper outlines the evolution of the data acquisition strategy for the Khazzan and Ghazeer assets. The development plan at project sanction was 20 vertical and 272 horizontal wells. The data acquisition strategy led to the development of a data acquisition plan, and all stakeholders were engaged to ensure the right data was acquired in the right place at the right time. Cross functional behaviours and fiscal discipline were essential in this process. Inclusion of the service companies into the wider BP team was crucial to ensure appropriate technology was applied, learning from previous operations implemented and new technology options made available.
Through careful management of the data acquisition plan, all data in development wells prior to first gas were acquired within the allocated data acquisition budget despite drilling 20% more wells than originally planned for this period. Early improvement in subsurface understanding enabled an overall reduction in well count for the life of the project, extension of the original development into unpenetrated areas, adding significant value to the project.
The Amin formation is a tight sandstone formation, that is present in Block 61 in the Sultanate of Oman, that has presented a number of development challenges. The Amin reservoir is characterized by an average permeability approximately two orders of magnitude lower than the Barik formations, which is the other main current development reservoir within the field. Adding to the challenge is the presence of the immediately and extensively underlying Buah formation, which is known to be sour.
During the Appraisal phase of the project, two vertical wells and one horizontal well were completed in the Amin, demonstrating that a horizontal well profile with multi-stage fracturing would most likely be required to achieve consistently commercial rates. It was also evident, even during the project sanction, that significant further investigation would be required to be able to more completely understand the hydraulic fracture behaviour in the Amin; in terms of the created fracture geometry, appropriate hydraulic fracturing methodology, suitable formation connection techniques, and other completion design factors to succeed with a reservoir development. Additionally, it was known that understanding reservoir fluid distribution would be fundamental to delivering such wells.
During the Development phase several vertical wells were completed with a range of fracture types and designs, to facilitate an assessment of well performance in the vertical geometry, as well as understand the fracture height for various hydraulic fracturing techniques, including High Rate Water Fracturing (HRWF) treatments as well as Hybrid-Frac (HF) type approaches. Additionally, several horizontal wells were also completed to build upon the Basis of Design (BoD) that had been selected at the end of the Appraise phase, with a continuous learning approach taken to further develop the frac understanding. Lessons more recently learned from North American unconventional reservoir stimulations were also investigated, carefully selected and then subsequently applied in a coherent and systematic way.
This paper presents a review of several of these vertical wells and two horizontal wells, attempting to demonstrate the progress made between the approaches. Additionally, the two horizontal wells will be used as a case study to illustrate the application of the continuous improvement methods, as well as the adoption of some key appropriate technologies transferred from North American unconventional reservoir stimulation approaches. These included an investigation of perforation cluster efficiency, the baseline fracture design and fracturing fluid types; as well as integrating directly with the open-hole characterization and production logs to enhance the frac designs and results.
The Middle East region holds substantial resources of unconventional tight gas and shale gas. The efficient extraction of these resources requires significant technology and expertise across numerous disciplines, including reservoir description and geomechanical characterization, hydraulic fracture modelling and design, advanced numerical simulation capabilities, sensor and surveillance technologies, and tightly integrated workflows. The effective application of these integrated subsurface and completion workflows leads to improved capital efficiency and well performance through increased well potential, increased ultimate recovery, and reduced costs. Key elements include dynamic rock typing to highlight potential flow units that will maximize gas deliverability, geomechanical modelling to provide a calibrated stress profile, and an integrated model that demonstrates the importance of understanding both dynamic flow properties and geomechanical response in complex tectonic environments. Dynamic rock typing focuses on using both depositional and petrophysical properties including rock type, porosity, and effective gas permeability at reservoir conditions to divide the reservoir into flow units in the context of their saturation history.
The petrophysical evaluation of tight gas formations has traditionally been centered on calculations of porosity and water saturation. These two parameters are used to quantify the original volumes in place but they do not provide information about phase mobility except at the saturation endpoints in high porosities. Low porosity affects the accuracy of water saturation calculations and can often make them ambiguous, leading to wrong decisions and unwanted water production.
We found dielectric dispersion logging to be a robust technique for determining gas pay zones independently from saturation equation input parameters. Dispersion analysis of the conductivity and permittivity measurements acquired by these tools is a function of the water tortuosity factor (mn). This factor is vitally important for accurate water saturation evaluation, but is often unknown or variable.
Nuclear magnetic resonance (NMR) measurement has the potential to enhance traditional formation evaluation techniques by providing estimation of the irreducible water saturation (Swirr) and permeability throughout the interval of interest. Accurate determination of these parameters benefits the selection of perforation intervals and improves the chances of producing maximum hydrocarbon with minimum water. NMR logging of deep tight gas formations poses unique challenges with regards to data acquisition due to low porosity, high temperature, and frequently saline muds. Pulse sequences and quality control procedures are used to validate the NMR measurements at high temperatures and high salinities.
An interpretation workflow was developed to integrate dielectric dispersion and NMR data and the results compared with more traditional formation evaluation techniques. There were significant improvements in the prediction of hydrocarbon- and water-producing intervals. The technique has been applied in several deep, high-temperature, low-porosity gas wells. These analyses are made in a timely fashion to provide operators with information for making better completion decisions.
Rylance, Martin (BP Exploration) | Nicolaysen, Arild (BP Exploration Co. Ltd.) | Judd, Tobias Conrad (Schlumberger Oman & Co LLC) | Ishteiwy, Omar A. (Schlumberger Oman & Co LLC) | Huey, Troy (Schlumberger) | Giffin, Wade Jonathon (Titan Global Oil Services)
Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Middle East Unconventional Gas Conference and Exhibition held in Muscat, Oman, 31 January-2 February 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract All tight gas project appraisals are inherently dependent upon the ability to execute effective fracturing treatments; that allow the determination of sustainable production rates; and hence potential project economics. Unlike the North American tight gas business, where thousands of wellbores are drilled each year and operational infrastructure and service quality is proven and in place; the International gas market challenges are significantly different. The Khazzan-Makarem structures have substantial known hydrocarbon reserves; which to date have resisted an economic development.