Development drilling operations in the Zuluf Field / Khafji Reservoir (offshore Saudi Arabia) involve targets near the flanks of the main structure, where oil-filled sands are sandwiched between overlying gas and underlying water. Horizontal well technology is utilized to increase the reservoir footprint. This article relays recent geosteering examples in the Khafji Sand bodies. Demonstrated results show significant gains in well productivity through an advanced well placement procedure relying on real-time geosteering. An asset team implemented a process of well placement in order to maximize the reservoir contact while drilling1. The process involves continuous exchange of information between the well site and the office-based teams to allow fast and informed decisions. The success of the well placement process has been enhanced by preparation prior to drilling, continuous interpretation of the real time data while drilling and integrated teamwork throughout the project. A key technology in the well placement process is the use of realtime borehole density images in addition to the standard LWD data. Continuous interpretation of the image data (providing bed dip and thickness) and correlation of the LWD data, with the offset well data and geological models, provided the information necessary to maximize the reservoir contact "net pay" along the horizontal lateral section. A series of wells have been drilled using the advanced well placement process. Examples illustrate how real time interpretation of the data by the team increased the net to gross ratio from 35% to 50%. The resultant increase in production demonstrates the value and the necessity of the process in the ongoing development of the field. Introduction The Zuluf field is located in the Arabian Gulf, approximately 149 miles (240 kilometers) north of Dhahran, Saudi Arabia, in an average water depth of 118 feet. Discovery of the field was made in 1965 and 270 wells have been drilled to date. The Khafji Reservoir is part of the Khafji Member of the Middle Cretaceous, Wasia Formation. The Khafji Member conformably overlies the Lower Cretaceous, Shu'aiba Formation and in turn is conformably overlain by the Safaniya Member. The Khafji reservoir in the Zuluf field consists of a thick sequence of quartz-rich sandstones, siltstones, shales and various types of ironstones (siderite, chamosite, and glauconite). Minor amounts of limestone and a few coal beds are also present. The average reservoir porosity is 30 percent and average permeability is greater than 1 Darcy. The Khafji reservoir was deposited in a fluvial-dominated delta system which prograded over the shallow marine carbonate platform of the Shu'aiba Formation. The Khafji Member ranges from 625 to 875 feet in thickness and is subdivided into four major stratigraphic units (figure 1). The uppermost unit, the "Upper Khafji Shale", is essentially shale with occasional thin reservoir sands. The next unit, the "Upper Khafji Stringers", consists of interbedded sands and shales with minor amounts of ironstone (mainly siderite), and very thin coal layers. Below the stringer sands is the "Main Sand", made up of thick massive sands 200 to 300 feet thick. The lowermost unit, the "Lower Khafji Stringers", is predominantly shale with minor interbedded reservoir sands. The majority of wells drilled to date are vertical and have targeted the "Main Sand" member. As drilling technology has advanced it has now become possible to target additional pay-zones within the "Upper Khafji Stringers" which are best developed on the flanks of the reservoir structure.
Significant wellbore instability problems are being experienced during the drilling of horizontal wells in a shaly sand member of the Khafji reservoir in Zuluf field. This paper presents the results from a case study that integrates detailed rock mechanics and swelling tests with information from petrophysical logs and core properties acquired to evaluate, define and predict the instability mechanism in this portion of the Khafji reservoir. The study has tackled the effect of drilling fluid on shale strength and swelling. Additionally the effects of water activity, osmosis and hydraulic diffusion on shale stability were investigated. The mechanical properties and stress field in the khafji shale was determined. The results provided recommendations to minimize instability problems encountered during drilling. All drilling fluids that have water phase including the oil-based drilling fluid were found to cause instability problems. However all-oil drilling fluid was found to maintain shale strength. Drilling mud salinity to encourage reverse osmosis was determined based on measurement of shale-pore-water salinity. The critical mud weight window was calculated considering the Chemoporoelastic properties of the Khafji shale. Introduction Drilling through shale formation usually causes over 90% of wellbore stability problems. These problems can be a simple washout to complete collapse of the hole. The problems of shale stability are related to the mechanical properties (strength and deformation under stress), the drilling fluids properties (weight, chemical makeup and brine concentration), the in-situ stress field, time dependant temperature, and time spent in open hole. Drilling extended-reach wells with long open hole intervals has been increasing. Oil based mud (OBM) have been the industry choice for difficult drilling. Their application has been typically justified on the basis of borehole stability, fluid loss, filter cake quality, lubricity, and temperature stability. Water-based muds (WBM) are attractive replacements from a direct cost point-of-view. Past efforts to develop improved WBM for shale drilling have been hampered by a limited understanding of the drilling fluid/shale interaction phenomenon. This limited understanding has resulted in drilling fluids designed with non-optimum properties required to prevent the onset of borehole instability. Modeling has been used to determine the mud weight window to minimize wellbore instability. In this study we used PBORE-3D developed through the Rock Mechanics Consortium of the Oklahoma University.
This paper describes the unique development plan of the M field, a giant offshore field with an areal extent of more than 800 square kilometers (km 2 ), laying under shallow waters northeast of Saudi Arabia. Due to the large number of wells to be drilled, conventional offshore development methods required over 30 offshore platforms to meet the production target efficiently. However, a novel drilling island concept in the form of a causeway was adopted, since the shallow water areas do not allow ocean vessels to set up the jackets and platforms. Utilization of a causeway, combined with the implementation of ultra extended reach drilling (ERD), reduced offshore operations to 11 platforms resulting in enormous savings to the operator.The backbone of the upstream infrastructure is the 20 kilometers (km) long, 11 meter (m) wide main causeway, and 25 drilling islands linked to it through 21 km of lateral causeways. The task of constructing these structures involves movement of more than 40 million cubic meters of sand and rock. The main causeway includes a 2,400 m bridge, in addition to five 150 m and eight 50 m bridges for minimal environmental impact on marine life.Being one of the largest drilling projects to be undertaken, with various reservoir, ERD, and logistical challenges were encountered during the planning and initial execution phases of the project. Meeting the expected production rate, at the lowest development and operating costs, in the safest and most environmental-friendly manner were the main drivers for the current plan. Reservoir heterogeneity, torque and drag, hydraulics, rigs specifications, well intervention, waste management and other specific challenges were overcome successfully using different techniques that are discussed in depth in the paper. OTC 20112Causeway and Offshore. This option involved constructing 27 man-made islands with 40% onshore development. The islands were to be connected with a causeway to allow easier future accessibility.Onshore, Causeway and Offshore. The final option was to maximize the use of the coast line by introducing ultra extended reach wells. This scenario would result in over 70% being onshore development.Evaluation. The whole life cycle costs were evaluated for the three options and assessed program estimates and construction risks in reaching its conclusion.The causeway had the lowest capital expenses, in addition to considerable reduction in operational expenses (40% of the project would be onshore operations). This option also allowed for a large number of drilling slots for future wells to maintain potential. Finally, applying extended reach drilling added significant additional savings.The conventional offshore operations requires normal high safety measures, however, causeway utilization is a unique operation in many aspects. Consequently, a Risk Assessment (RA) study was conducted by a third party consultant for drilling at onshore sites and causeway islands to identify hazards and minimize risks to by implementing safe guards. The major challenge was...
Over the past decades, environmental regulations for oil and gas companies have become increasingly more stringent to protect and preserve the environment for future generations. This is particularly true for remote areas and environmentally sensitive terrestrial and marine locations where there is a strong emphasis on protecting natural habitats and resources. Accordingly, many regulatory agencies have adopted "zero discharge" policies requiring all generated wastes to be disposed in a responsible manner. For drilling operations, the various waste streams that need to be handled and disposed of properly include: drill cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and even production and cleanup waste. Old practices involve temporary box storage and hauling of the waste products to a final disposal site. Often, these sites are several kilometers (km) away from the generation source, creating not only liabilities for the operating company, but also environmental risks from accidental releases and gas emissions that result in higher operating costs.To address these concerns, waste management technologies have evolved to offer cuttings re-injection (CRI) as a safe and cost-effective alternative that permits the permanent and contained disposal of drilling cuttings in an engineering-determined subsurface formation. CRI provides a secure operation achieving "zero discharge" by injecting cuttings and associated fluids up to several thousand meters below surface into hydraulically created fractures. This disposal technique mitigates any surface environmental risks and future liabilities for operating companies.Saudi Aramco has taken the initiative to utilize CRI as the preferred technology to manage drilling wastes that will be generated in the Manifa field development. To minimize risks associated with CRI, and conduct successful injection operations, an Assurance Waste Injection Process was set in place to continuously monitor the operation and plan ahead for any eventuality. Assurance of the injection operation begins during the planning phase with a comprehensive feasibility study based on existing data. Simulations are performed for the anticipated downhole waste domain to ensure containment within the selected formation and permit adequate design of surface facilities for the particular project.This paper describes the various components of the first Saudi Aramco CRI "pilot" study. These include: reservoir/geomechanical data analysis and interpretation; preliminary geomechanical modeling; target zone selection; test well design, drilling and injectivity testing; and geomechanical model refinement using field injectivity data. The objectives of this study for the Manifa field development project were to evaluate:• What are the most promising zones for injection based on the geomechanical model? • Do overlying formations provide effective containment of the injected wastes? • What are the injection rates, volumes, slurry rheology, and particle size requirements for fi...
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