Estimates place unconventional natural gas reserves in the Kingdom of Saudi Arabia at over 600 trillion cubic feet, more than double its proven conventional gas reserves. Domestic consumption fuels the economy as well as social spending, and the leadership is heavily invested in global research and development centers to become leading innovators in the industry. There is evidence of current commitment to develop natural gas projects in 3 offshore fields and construction of a 1, 000 MW gas-fired power plant. Despite political will for resource diversification in Saudi Arabia, there are hurdles in the form of processing capacity, logistics, water supplies and desert terrain, which could adversely affect project economics. Lifecycle economic analysis indicates that under current market conditions, development of unconventional gas projects could be challenging.
A breakeven economic analysis of the country's gas supply sources tests this supposition by assessing unconventional field development lifecycle costs and off-take pipeline infrastructure costs. Our analysis reveals that a breakeven price for domestic unconventional gas in Saudi Arabia ranges from roughly $5/Mcf to $8/Mcf depending on a range of pipeline scenarios. The study further explores several gas supply scenarios incorporating the commercialization of Saudi Arabia's unconventional resource assets, LNG imports, and pipeline imports from Qatar. In lieu of short-term unconventional gas supply, overall findings suggest pipeline gas from Qatar offers the lowest cost option, although LNG from Yemen or Nigeria ranks as a competitive resource alternative for additional near-term supply.
With globally increasing demand for hydrocarbons, finding and developing unconventional resources has become a global necessity. Outside North America, shale gas discoveries have been made in recent years; however, significant commercial production has been limited to North America. Finding and developing unconventional resources outside North America is the next big challenge for the oil and gas industry.
Although the reported potential of unconventional gas resource volumes in MENA are almost similar in size to US, presently the exploration and development of such resources has been very limited. Unconventional reservoirs have very different and distinct requirements from conventional reservoirs. The more ‘unconventional’ targeted a resource is, the more difficult it is to develop. Furthermore, for these difficult resources, highly specialized technologies need to be applied by considering their unique requirements.
Key challenges specific to the MENA region include the following:
- Limited exposure to unconventional sources leads to lack of infrastructure, high cost,
- Reservoir characteristics (rock and fluid properties) and geo-mechanics,
- Implementation of directional and horizontal drilling technologies suited for the region,
- Most challenging aspect is hydraulic fracturing (fluid availability and management, fracturing fluid and proppant selection, fracturing design, equipment) as it incurs highest cost and exhausts maximum technological efforts.
This paper aims to highlight these associated challenges in developing unconventional resources and offers a potential approach to evaluate unconventional resources. Additionally, public data are reviewed and emerged technologies are used to unlock the potential of unconventional resources in MENA.
A major service company has exhaustive and varied data from different geographies, resources type captured in its State-of-The-Art data center. A comparative case study is included which extrapolates historically available data specific to directional drilling, frac treatment designing & analysis and fluid management to MENA conditions to depict and overcome the challenges of unconventional resources.
Nanoparticles (D~1 to100 nm) as part of nanotechnology have drawn the attention for its great potential of increasing oil recovery. From the authors’ previous studies, wettability alteration was proposed as one of the main Enhanced Oil Recovery (EOR) mechanisms of nanoparticles fluid. Adsorption of nanoparticles on pore wall lead to wettability alteration of reservoir. We conducted a series of wettability measurement experiments with water, neutral and oil wet core plugs, where we systematically varied nanoparticles concentration and size of nanoparticles. Nanoparticles transport experiments were also performed for three different wettability core plugs with varying flow rate, injection pattern as well as concentration and size of nanoparticles. Effluent nanoparticles concentration was measured to evaluate nanoparticles adsorption and retention in the core and also desorption during water post-flushes afterwards. Both silica hydrophilic nano-structure particles and colloidal nanoparticles were utilized in above two experiments.
The results of wettability alteration experiments indicated that hydrophilic nanoparticles have ability of making the cores to more water wet, especially for neutral and oil wet cores. Concentration and size of nanoparticles have significant effect during wettability alteration process. For nanoparticles transport experiments, the results showed that the nanoparticles undergo both adsorption and desorption as well as retention during injection. Effluent nanoparticles concentration curves were plotted to find the breakthrough time. Experiments with varying concentration, particle size and flow rate yield magnitude of nanoparticles adsorption and desorption ability for Berea sandstone. Porosity and permeability impairment were observed during nanoparticles dispersion injection.
Shale gas development is characterized by a composite of several experience curves in terms of operations, resource assessment, and infrastructure development. More specifically, the learning curve for the operator grows as operational characteristics are fine-tuned, such as experience ramp-up, logistics and supply chain optimization, and factory-style operations. Technical understanding of the basin then grows as operators learn how to design and execute the most suitable horizontal well trajectory; how best to land the lateral section in the pay zone; where to perforate the formation; how to optimize perforated sections, number and size of frac stages; and where the sweet spot is located relative to asset sections with marginal economics. Supporting infrastructure must grow in pace with development growth, which is also influenced by the fine tuning of supporting policy and regulations, resulting wellhead costs, and market factors. Each phase is characterized by associated costs and uncertainties. A field-wide shale gas economic model has been created as an extension of our original single-well economic model, which captures the various phases of unconventional resource development. We tested the base model against North American shale basins; fundamentals of the same model have then been adjusted to assess unconventional development in the Middle East, and then specifically calibrated to analyze the Qusaiba shale in Saudi Arabia. Model results for Saudi Arabia shed light on the commercial feasibility of shale gas development in the country, along with operational constraints and limitations. While broad findings apply to the Middle East as a whole, country-specific modeling will reveal specific operational issues that must be addressed in the course of development of unconventional resources in the region.
Briner, Andreas P (Petroleum Development Oman) | Moiseyenkov, Alexey Vladimirovich (Shell) | Prioul, Romain (Schlumberger) | Abbas, Safdar (Schlumberger - Doll Research) | Nadezhdin, Sergey Valentinovich (Schlumberger) | Gurmen, Mehmet Nihat (Schlumberger IPM-SPM)
A recent series of tight gas discoveries in the Amin formation of the greater Fahud area represents some of the most exciting exploration success of this decade in the Sultanate of Oman. The structures have been evaluated as containing very significant amounts of gas locked in a challenging deep and hot environment requiring hydraulic fracture stimulation. Since their discoveries, the two primary challenges have been difficult breakdown of the formation and limited proppant placement during stimulation attempts. The early experience in the exploration and appraisal campaigns from 2009 to 2014 has led to fracture designs with conservative proppant amounts that could limit the full potential of the field. Several geomechanical studies have been commissioned in the past to guide completion strategies in well placement, perforation, and fracture stimulation design. The objectives of this study were to model hydraulic fracture initiation and breakdown in the three Amin zones (upper, middle, and lower) to provide some theoretical understanding of the impact of the different parameters on the observed field breakdown pressures. In agreement with field observations, the model showed that lowering the viscosity of the pad has a major impact in lowering the breakdown pressures. Consequently, current best practices include formation breakdown and hydraulic fracture propagation with low-viscosity fluids followed by proppant placement with high-viscosity fluids. When applied to tight gas formations in the Sultanate of Oman, the hybrid fracturing evolves from conventional designs for the purpose of successful fracture initiation, while still placing a successful job.
This paper outlines how a drilling team is meeting the challenge of cementing a production liner in deep horizontal drain sections in a tight sandstone reservoir. It is intended to show how the application of existing technologies and processes is leading to performance gain and improvements in cementing quality. The full field development plan of the tight reservoir gas project in the Sultanate of Oman is based on drilling around 300 wells targeting gas producing horizons at measured depths of around 6,000m MD with 1,000m horizontal sections. Effective cement placement for zonal isolation is critical across the production liner in order to contain fracture propagation in the correct zone. The first few attempts to cement the production liner in these wells had to overcome many challenges before finally achieving the well objectives. By looking at the complete system, rather than just the design of the cement slurry, the following criteria areas were identified: - Slurry design - Mud removal and cement slurry placement - Liner hanger and float equipment Improvements have been made in each of these areas, and the result has been delivery of a succesfully optimised liner cementing design for all future horizontal wells.
The heterogeneous nature of oil shale resources associated to the depositional environments, lithology, and organic content make the reserve estimation complex and unpredictable. However, comprehensive laboratory studies on organic rich shale samples collected from different regions can increase the understanding about the organic content of oil shales, interaction of shale with organic matter and injected fluid used during enhanced oil recovery method. This study investigates the characterization of eight different Turkish and American oil shale samples with several spectral methods and a thermal analysis. The main purpose of this study is to characterize the oil shale samples to increase the understanding about the organic content and interaction of shale with organic matter.
In this study, we used Thermal Gravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) analysis in order to estimate organic content of each oil shale sample in air and nitrogen environments. X-Ray Diffraction (XRD) was used to define minerals in oil shale. Fourier Transform Infrared Spectroscopy (FTIR) was used to detect the mineral and kerogen in oil shale before and after the TGA/DSC analysis. Scanning Electron Microscope (SEM) was used to characterize the depositional environment of each oil shale samples.
TGA/DSC results verified that oil shale samples have up to 40% of organic matter. XRD and FTIR results helped to identify the organic and inorganic compounds. Effects of minerals and ions were recognized by comparing TGA/DSC curves and FTIR spectra. It was recognized that the more carbonate ion in the oil shale the more increase in weight loss occurred. Diatoms identified from SEM results showed that depositional environments of the oil shale samples are mostly marine environments.
This study provides insight for the reserve estimation of the eight different oil shale samples with comprehensive spectral and thermal characterization.
Dernaika, Moustafa (Ingrain Inc) | Aljallad, Osama Ali (Ingrain Inc) | Koronfol, Safouh (Ingrain Inc) | Suhrer, Michael (Ingrain Inc) | Teh, Woan Jing (Ingrain Inc) | Walls, Joel D (Ingrain Inc) | Matar, Saad Awad (Kuwait Oil Company) | Murthy, Natarajan (Kuwait Oil Company) | Zekraoui, Mohammed (Kuwait Oil Company)
The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors including total organic carbon (TOC) content, mineralogy, maturity and grain-size. The ultra-low permeability of the shale rock requires massive hydraulic fracturing to enhance connectivity and thus permeability for the flow. To design an effective fracturing technique, however, one must have a good understanding of the reservoir characteristics and fluid flow properties at multiple scales.
In this work, representative core plug samples from a tight carbonate source rock in the Middle East were characterized at the core and pore scale levels using Digital Rock Physics (DRP). The tight nature of those carbonate rocks hindered the use of conventional methods in measuring special core analysis (SCAL) data. Two-dimensional Scanning Electron Microscopy (SEM) and three-dimensional Focused Ion Beam (FIB)-SEM analysis were studied to characterize the kerogen content in the samples together with (organic and inorganic) porosity and matrix permeability. The FIB-SEM images in 3D were also used to determine petrophysical and fluid flow (SCAL) properties in primary drainage and imbibition modes.
A clear trend was observed between porosity and permeability in relation with identified facies and organic matter in the core. Kerogen was found to have direct effect on the imbibition two-phase flow relative permeability and capillary pressure behavior and hysteresis trends among the analyzed samples. The obtained data from DRP provided information that can enhance our understanding of the pore systems and fluid flow properties in such tight formations, which may not be derived accurately using conventional methods.
Chun, Kuang Li (Petrochina Xin Jiang Oilfield Company) | Xu, Jingwen (PetroChina Xin Juang Oilfield Company) | Jun, Mao Xin (Petrochina Xin Jiang Oilfield Company) | Chen, Chaofeng (PetroChina Xin Juang Oilfield Company) | Li, Xuebin (PetroChina Xin Juang Oilfield Company) | Judd, Tobias Conrad (Schlumberger) | Liu, Yuan (Schlumberger) | Liu, Hai (Schlumberger) | Jing, Li (Schlumberger)
The necessity to exploit hydrocarbon resources further down the resource triangle has resulted in the industry in attempting to evaluate large and more challenging resource plays due to the scarcity of conventional reserves. The Jimusaer Field located in the Junggar Basin in West China, represents such a scenario and covers a surface area exceeding 300,000 acres with a targeted reservoir thickness of 650 feet located between 9,100 and 14,500 feet TVD.
Typical exploration programs include extensive data collection of reservoir and hydrocarbon properties with respect to structural location. The assessment and evaluation of such data improves the understanding of the sub-surface uncertainties and associated risk. Given the uncertainty in well productivity, increased attention to the hydraulic fracturing process was required and included the application and combination of several types of technology which was built upon and optimized through the initial 28 vertical wells.
In order to further improve well performance, the application of long horizontal laterals combined with multi-stage hydraulic fracturing was needed in order to provide proof of commercial productivity and subsequent field development which for several years was not thought to be possible. Based on the initial vertical well results, three horizontal well were designed based upon the improved reservoir understandings. This phase was meant to further advance the understanding of the subsurface and completion and stimulation technologies while identifying areas for future productivity improvement.
Finally, the unique geological properties of this reservoir required different strategies and technology deployment in order to make them viable and sustainable in terms of reservoir and completion quality factors. The successful application of a locally developed technology plan and pilot program through a multidiscipline approach further demonstrated the suitability of a given technology with the lesson learned being captured and incorporated into future well designs.
Over the last decade productive capacity of both oil and gas from uneconomic North American unconventional shale resources has been dramatically enhanced due to advanced horizontal drilling technology combined with multi-stage hydraulic fracturing treatment maximizing access to productive zones. Currently two types of multi-stage fracturing completion systems are in common use:
• The conventional Plug-and-Perf (P-n-P) method in cased hole.
• Frac sleeves using open hole (OH) packers or cementing to isolate multiple stages.
To streamline the fracturing process, a new pressure-activated toe sleeve has been developed for both multi-stage fracturing methods, and is run in the hole on the bottom of the completion string and actuated after two pressure applications. This sleeve isn’t open after first pressure application, so casing integrity testing can be conducted and pressure can also be held indefinitely to satisfy regulatory requirements. As the second low pressure is applied, the sleeve can lock open, then composite plugs for P-n-P or balls for frac sleeves multi-stage system can be pumped down to begin subsequent stimulation operations. This toe sleeve is especially beneficial in P-n-P completions as an alternative to tubing conveyed perforating (TCP) to initiate pump-down operations, and is able to eliminate the initial perforation run to perforate the first stages at the toe of the wells for P-n-P operations.
This paper will present the operational mechanisms of this unique toe sleeve with two pressure applications to open this sleeve by adding significant operating efficiency and lowering the cost of multi-stage fracturing.