Zillur Rahim

The function of fractures and in-situ stresses in the Khuff reservoir performance, onshore fields, Saudi Arabia

The highly variable performance of the Permian–Triassic Khuff reservoir in onshore Saudi Arabia has been attributed to the presence of natural fractures. Similar preproduction pressure profile and hydrocarbons in the different reservoir units in some fields have been attributed to vertical communication through large faults. To validate these assumptions, we studied the static and dynamic data from the Khuff reservoir in 19 major structural traps. We identified two distinctive fracture domains based on fracture orientation and density. Fracture evolution is mainly controlled by the extensional and consequent compressional plate tectonics instead of local structures. In-situ stresses are dominated by the Zagros plate tectonics and affect fracture aperture differently in the two fracture domains. The fracture impact on the Khuff reservoir performance is mostly subtle because of the nature and distribution of the fractures. High fracture-enhanced productivity occurs locally in some of the producing wells, and it results from high-density fracture clusters (including mesoscopic faults) with channel-type apertures. The following findings challenge the perceived major functions of fractures in the Khuff reservoir performance in onshore fields: (1) Individual fractures are dominantly tensile and small (mesoscopic and microscopic); (2) individual faults are small and not readily resolvable at seismic scale; (3) the depth and carbonate nature of the Khuff reservoir make the fractures highly susceptible to fast healing unless preserved within the hydrocarbon column; (4) initial vertical pressure gradient changes with production indicate a lack of present-day communication across the anhydrite sealing layers, between the different Khuff reservoir units; (5) horizontal well direction does not generally have an impact on productivity; and (6) sustained and heavy losses of circulation are rarely encountered in the Khuff reservoir wells. Mohammed S. Ameen received his Ph.D. and Diploma of Imperial College in structural geology and geomechanics from Imperial College, London, 1988. He has more than 20 years of academic and industrial experience and has patented a new method for the characterization of microfractured reservoirs. He has published 25 articles on fractures and folds, and has edited three special publications for the Geological Society (London). He conducted the first classic work on the fractures and folds across the Taurus-Zagros Range, Iraq, covering 30 major fold traps. The work is published in the AAPG Bulletin, the Geological Magazine, and the Journal of Petroleum Geology. He joined the Reservoir Characterization Department at Saudi Aramco in 1998. Since 2004, he has been leading the Structural Geology and Rock Mechanics Group in the Geological Technical Services Division, Saudi Aramco. He is an active member of the AAPG, Society of Petroleum Engineers, European Association of Geoscientists and Engineers, and the Geological Society (London). Ismail M. Buhidma is a petroleum engineering consultant in the Gas Reservoir Management Division of Saudi Aramco with 32 years of diverse industrial experience. For the last 12 years, he has been actively involved in Aramcos nonassociated gas development program. His areas of interest include reservoir management, well performance analysis, well test analysis, phase behavior, geomechanics, reservoir simulation, reservoir characterization, and well stimulation. Prior to joining Aramco, Ismail worked for Exxon in Libya, Schlumberger and Atlantic Richfield in the USA, and Qatar Petroleum in Qatar. Ismail holds B.S. and M.S. degrees in petroleum engineering from the University of Tulsa. He is a member of Society of Petroleum Engineers (SPE) and has published numerous SPE appears. Zillur Rahim is a petroleum engineering consultant with Saudi Aramco working in gas field development. He received his B.S. degree from Algerian Petroleum Institute and M.S. degree and Ph.D. from Texas A&M University, College Station, all in petroleum engineering. He has 25 years of industry experience, has published more than 50 technical papers, and has taught numerous industry courses. Previously, he worked with Holditch and Associates Petroleum Consultants and with Schlumberger Reservoir Technology group. His area of expertise includes reservoir engineering, hydraulic and acid fracturing, and reservoir management.

Diverse fracture properties and their impact on performance in conventional and tight-gas reservoirs, Saudi Arabia: The Unayzah, South Haradh case study

The Upper Permian–Carboniferous Unayzah Formation in South Haradh, Saudi Arabia, includes two major mechanical and petrophysical layers that are separated by shale-rich zones. Open tectonic fracture clusters are rare and not essential for fluid flow in the Unayzah A zone, which has high porosity and permeability. However, such fracture clusters are essential to, and impact, the production performance in the Unayzah B/C tight-gas reservoir. The occurrence of the tectonic fractures in the Unayzah Formation is linked to the rock mechanical properties, which vary with porosity, shale volume, cement type, and texture. The B/C unit is more fractured than the A unit, but its layers vary in the degree of fracturing. The variation in fracture development within the B/C unit results in differences in fracture-enhanced permeability based on production profiles where flow is restricted to preferentially fractured mechanical layers that lack effective vertical fluid communication with other layers. We identify two tectonic fracture systems: an older subordinate fully mineralized system and a younger primary mostly open system. Early extensional fractures including joints and faults developed parallel to the basement faults during the opening of the Neotethys. These are fully mineralized and have little or no function as fluid conduits. The younger system includes open-fracture clusters that are predominantly parallel or nearly parallel to the regional east-northeast–west-southwest maximum horizontal stress of the Zagros (that has been active since the Late Cretaceous) and is independent of local structures. Therefore, these fractures are controlled by remote stresses instead of the basement-rooted forced folds and faults. In this article, we demonstrate that in the Unayzah B/C, natural fractures are essential to permeability and, in some areas, to porosity, and thence, to reservoir performance. The results of this study are being implemented in well placement and completion design to optimize the intersection of open-fracture clusters with positive preliminary results.

Success Criteria for Multistage Fracturing of Tight Gas in Saudi Arabia

The purpose of open hole multistage fracturing (MSF) is to improve hydrocarbon production and recovery in moderate to tight reservoirs. To date, 17 open hole MSF systems have been installed in deep gas carbonate and sandstone wells in Saudi Arabia. Of these, 16 installations have been stimulated (acid or proppant fractured) and flowed back 1 . Overall, the production results from the use of open hole multistage systems deployed in the Southern Area gas fields have been very positive with some variation – most of the wells responded positively and are excellent producers (>20 million standard cubic feet per day (MMscfd)); some showed average results of 8-12 MMscfd; and a few, completed in a tight reservoir, produced at relatively low rates, <3 MMscfd, and did not carry enough wellhead pressure to be connected to the production grid. This article explores the factors that impact the success of open hole multistage completion systems. Some important factors include the type of open hole multistage system used, formation properties, completion liner size, packer type, number and size of stimulation stages, treatment type, well azimuth and fluids pumped. Conclusions are drawn based on careful data analysis to confirm the best practice for successful open hole multistage deployment and conducting effective fracture treatment. This article uses extensive field data and correlates factors to show the applicability of open hole MSF technology. Analysis will cover pre- and post-stimulation data showing the results from the treatments. This analysis will show the factors that contribute to the successful deployment of the completion system, the achievement of higher production rates, and the choice of the right candidates to obtain positive results from the treatment. This article will also show that while the various well and reservoir characteristics have a significant influence on overall well productivity, the completion type is critical and plays a central role in the success of the stimulation treatment and final production levels. Open hole multistage systems have been deployed

Using a three-dimensional concept in a two-dimensional model to predict accurate hydraulic fracture dimensions

Abstract Hydraulic fracture treatments can be used to increase the oil and gas flow rates and ultimate recovery. A fracture treatment should be designed to optimize profit from the well. To design and optimize the fracture treatment, an engineer should use (1) a fracture propagation model, (2) a reservoir fluid flow model, and (3) an economics model. Inasmuch as a fracture treatment design involves selection of fracturing fluids, proppants, pump schedule and injection rate, this three-step procedure is repeated several times to obtain the best combination. Using a three-dimensional fracture propagation calculation tool in such a case is difficult and time consuming. In this paper, an easier approach is presented to approximate the three-dimensional fracture geometry by a two-dimensional fracture propagation calculation model in order to save significant amount of computer time.

Effects of fracture fluid degradation on underground fracture dimensions and production increase

Abstract A detailed computer study has been conducted to determine the effects of fracture fluid rheological characteristics upon fracture growth, proppant transport and placement and ultimate gas recovery. Several examples presented in this paper illustrate that an effective fracture fluid quality control needs to be implemented in order to achieve the desired fracture dimensions and production performance as computed during design procedure. Several actual cases show how the fracture fluid can degrade in quality due to variations in fluid additive concentrations, inefficient mixing procedures, and many other factors. This fluid degradation can lead to inadequate fracture dimensions, poor proppant transport, and loss in ultimate well recovery. The quality of fracture fluid can be effectively maintained by continuously measuring fluid characteristics in the field and controlling its viscous properties by modifying fluid additives, injection rate, etc., during the actual execution of a stimulation treatment. A three-dimensional hydraulic fracture model has been used to compute fracture and proppant characteristics for a wide range of field measured fluid properties in order to illustrate the impact of fracture fluid upon fracture dimensions and proppant transport. Using data computed by the fracturing model, a single-phase analytical model has then been used to predict gas production and ultimate recovery.

Evaluation of fracture treatments using a layered reservoir description: field examples

Abstract A practical analysis technique for the determination of actual fracture geometry and proppant profile using a three-dimensional hydraulic fracturing simulator is presented in this paper. A guideline has been presented to properly describe the treatment interval, analyze the fracture treatments using field measured data, and to confirm the results using pressure transient tests and production data analysis. The examples illustrate that detailed description of the reservoir layers is essential to properly evaluate hydraulic fracture treatments. Application of this methodology requires the study of well logs. These logs (particularly the gamma ray and resistivity) allow the engineer to differentiate layers within the interval based on lithology and porosity. These logs are also used to estimate in-situ stress, permeability and porosity of such layer. A three-dimensional fracture propagation model that uses the detailed mechanical and fluid information from all layers is crucial for accurate analysis.

The effects of mechanical properties and selection of completion interval upon the created and propped fracture dimensions in layered reservoirs

Abstract A finite-difference, hydraulic fracture treatment simulator that computes fracture dimensions in a layered reservoir is presented in this paper. Each layer can have different mechanical and fluid flow properties. The model allows initiation of the fracture in multiple producing intervals simultaneously. This pseudo-three-dimensional model has been used extensively to study the effects of reservoir mechanical properties, particularly stress distribution, Youngs modulus, and fracture toughness of the reservoir layers on the height of the fracture. Effects of fluid properties such as apparent viscosity and injected fluid volume on fracture height have also been investigated. The use of this model for different scenarios illustrates the effects of mechanical properties on fracture dimension and proppant transport. Several examples have been generated for reservoirs with multiple producing zones, in which the fracture is initiated in one or several intervals simultaneously, so that one can illustrate the effects of perforation placement upon the distribution of proppant within the fracture. These examples illustrate that the location of the perforations can substantially affect the final proppant profile. The propped fracture geometry is used in a single-phase finite-difference reservoir simulator to show the production increase and long-term production performance for different scenarios.

Selecting perforation intervals and stimulation technique in the Khuff reservoir for improved and economic gas recovery

Abstract Saudi Aramco has initiated an acid fracturing program to treat the carbonates of the Khuff reservoir in the Ghawar field in the eastern province of Saudi Arabia. Khuff reservoir belongs to the Permian age and is encountered at an average depth of about 11,500 ft. Two main producing intervals of this reservoir, Khuff B and Khuff C, have tested high quantity of condensate-rich gas. Khuff reservoir consists mainly of dolomite and limestone sections with streaks of shale and anhydrite that constitute the nonpermeable and possible fracture barrier zones. The reservoir extends up to several hundred feet in thickness with varying quality and production potential. A careful planning of completion technique and choice of stimulation is important for efficient fracture coverage and improved hydrocarbon recovery. This paper addresses the general methodology of selecting perforation intervals and stimulation technique to develop and enhance production in the Khuff carbonate gas reservoir.

Using a Mixed Integer Linear Programming Technique to Optimize a Fracture Treatment Design

The design of the optimum fracture treatment has three basic steps. The first step involves calculating fracture dimensions and conductivity for various fracture fluid pumping schedules. The second step is determining the oil and gas production rates and recoveries using the values of propped fracture length obtained from the fracture treatment design. The third step requires one to determine the optimum fracture treatment design by maximizing the economic benefit of the treatment. Since a fracture treatment design involves selection of fracturing fluids, additives, proppant materials, injection rate, pump schedule, and fracture dimensions, the determination of the optimum combination of all variables can be quite complicated. In this research, the authors have developed two methods to investigate reasonable combinations of design and treatment parameters to determine the most profitable fracture treatment design. Depending upon the post-fracture treatment production rates, the related expenses, and the economic constraints, the optimum treatment can be easily determined.

Wellbore Stability Analysis Using Acoustic Radial Profiles and an Elastoplastic Model

Wellbore instability during drilling, completion, and production is an important and costly issue in many oil and gas fields. Because field observations show that stress-related wellbore instability problems are frequently encountered, the main objective of this study is to establish a workflow for wellbore stability modeling. The workflow was created using finite element wellbore modeling to predict induced stress concentrations and rock yield around the wellbore. Elastoplastic models were used in conjunction with the Mohr-Coulomb and other yield criteria. The second objective was to constrain these models using dipole radial profiles from an acoustic scanning platform.