TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents an in depth study for a field-wide application of Maximum Reservoir Contact (MRC) wells along with smart well completions complemented by openhole expandable tubular to develop Haradh Increment-3, the southernmost area of the greater Ghawar Field. The reservoir represents a heterogeneous matrix permeability background, with geological discontinuities such as faults, fractures, and stratiform high permeability streaks. An MRC is a multi-lateral horizontal well with more than 5 km. of total contact with the reservoir rock (1,2) .This paper illustrates how an MRC well with smart completion was designed with objectives for higher productivity, better pressure transfer between laterals, delay in water encroachment by down hole control, and higher cumulative production. The design was based on highly detailed dual porosity and dual permeability cross-sectional, sector and full field simulation models in addition to field trials.

Haradh forms the southernmost part of the super giant Ghawar oil field located about 80 km (50 miles) onshore from the Arabian Gulf, in the Eastern Province, Kingdom of Saudi Arabia (Fig. 1). A major feature of the Ghawar field is its tilted Original Oil Water Contact (OOWC), getting shallower from North to South Ghawar at an average gradient of 0.36 m (1.2 ft) per km. In Haradh, the OOWC displays also a large but localized west-to-east component. Understanding the OOWC tilt mechanisms is vital since it will improve the effectiveness of the on-going Oil-Water Contact (OWC) delineation program. This will result in better placement of future producers and injectors, which in turn will reduce the cost of future developments. Statement of Theories and Definitions To date, two major concepts have been proposed to explain the tilted OOWC in Ghawar and more particularly in Haradh:One is that the OOWC tilt is caused by regional changes in reservoir fluid densities1.Another hypothesis is a dynamic flowing aquifer hitting the Ghawar field on Haradh west flank and pushing the OOWC to a shallower level along its south to north journey2. In summary, a static concept of the equilibrium is confronted to a dynamic one. The existence of pre-production pressure gradient in the field has to be verified to support a dynamic cause of the OOWC tilt. Integrating field temperature, salinity and pressure data as arguments, these hypotheses are critically discussed. During this process, a causal link to a major tectonic accident is proposed. Introduction Berg completed the surface mapping of the Haradh structure in 19403. Wildcat HRDH-1 struck oil in the Arab-D reservoir (Jurassic) in 1949. The first OOWC delineation wells were drilled during the seventies. Although 'Ain Dar and Shedgum (North Ghawar) areas are on stream since 1951, very limited production occurred in Haradh until 1996 when Haradh Increment-I (North Haradh) was put on stream to reach the required production plateau (Fig.2). Prior to that date, the OOWC was roughly defined by several delineation wells with a spacing of 16 miles. A fresh look at existing field data, recent advances in regional tectonics and simulation results all support a static origin of the OOWC tilt and confirm the conclusions of a previous work1. Description of the Haradh OOWC Haradh delineation wells showed that:The OOWC gets shallower from north to south to reach -6,420 ft at the Haradh tip;The west flank OOWC gets locally 800 ft shallower than that in the east (Fig. 3). Note that western and eastern aquifer legs are separated by almost 15 miles of a large anticline structure with a maximum 3°-dip angle. Drill Stem Test (DST) samples of Well-A (Well location on Fig.2) showed that the formation did not contain recoverable oil to the top, which established the Highest Known Water (HKW) at -5,863 ft in the west and confirmed the Formation Analysis Log (FAL) (Fig.3). FAL of Well-B (Well location on Fig.2) showed that the formation contained high oil saturation throughout the good quality zones, which established the Lowest Known Oil (LKO) at -6,625 ft in the east (Fig.3). Aquifer water on the Haradh west flank is anomalously fresh (30,000 ppm TDS at Well-A) and recent (6,000 to 20,000 year-old), compared to the more saline water sampled on the east flank (120,000 to 150,000 ppm TDS). Recent isotopic analysis in the Dhahran Research and Development Labs4 showed the meteoric origin of the aquifer water sampled on Haradh west flank. Note: The Jurassic Arab-D reservoir was deposited some 150 million years ago.

The simulation of fluid flow in fractured reservoirs is mostly based on the Warren-Root formulation in which the matrix is dissected into blocks by fractures(1). In modern simulators, the Warren-Root formulation has been extended to account for fluid flow in the matrix as well as in the fractures(2). These two media of contrasting transmissibility and storage capacity constitute the basis of dual porosity dual permeability modeling. Hydraulic connection between the two media is managed via a transfer function. This formulation is appropriate for cases with diffuse interconnected fractures. Alternatively, fractures can be modeled explicitly by capturing their geometries, shapes and sizes in the form of numerical grid cells. But this would be prohibitively costly in terms of run time and memory. This paper presents a method that is suitable for giant fields that are dominated by clusters of sub-vertical fractures called fracture corridors. It is based on a hybrid approach of the two alternatives mentioned. The effective Warren-Root and fracture parameters are adjusted to mimic explicit fracture modeling thereby capturing the advantages of both. The method was applied to a giant carbonate field in Saudi Arabia, which has both fracture corridors and super-permeable bodies. These bodies are typically horizontal and they inter-connect with the fracture corridors to form a combined high conductivity medium which is responsible for the unusual water movement observed in some parts of the field. The full field simulation model contains a homogeneous matrix and a fracture grid comprised of fracture corridors and super-permeable bodies. Fluid segregation is assumed in the fracture system in agreement with the physics inside conductive vertical fractures. The matrix-fracture corridor and the matrix-super permeable body exchanges are represented in a manner similar to matrix-fracture transfers in the Warren-Root dual-porosity system. Special attention was paid to matrix block size and to imbibition capillary pressure. This approach led to a reliable history match that captures the water arrival time and water production profiles in the reservoir. Introduction Fluid flow in naturally fractured reservoirs primarily takes place via high permeability and low porosity fractures surrounding matrix blocks. The simulation of such reservoirs is challenging both in terms of characterization and numerical modeling. This paper addresses some challenging aspects of numerically modeling a special kind of fractured reservoir where fractures cluster together to form the so called fracture corridors, which are also known as fracture fairways or fracture swarms. Unlike diffuse fracture networks whereby fractures are distributed within reservoir matrix rock, reservoirs with fracture corridors are not readily approximated by the Warren-Root, so-called "sugar-cube" model. This is because fracture corridors (a) are large scale features that generally cut through the reservoir thickness, (b) exist along corridors while the vast part of the reservoir may or may not be free of fractures. Such large scale but clustered fractures are akin to major faults in some ways and could be modeled explicitly by approximating them as such. At the same time, we know they actually consist of a large number of individual and relatively small high conductivity openings that are clustered and aligned together. It is possible to model such configurations by using a modified set of Warren-Root parameters. In this paper, they are in effect approximated by the judicious choice of Warren-Root parameters as in dual media modeling so as to respect the fact that they are akin to major fault lines. This approach is applied in the Arab-D full field modeling. The Arab D reservoir is carbonate and oil bearing. The model is constructed using Saudi Aramco's POWERSTM simulator and contains a total of about 9 million cells.

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Summary This paper describes a case study that details the planning, completion, testing, and production of the first maximum reservoir contact (MRC), multilateral (ML), and smart completion (SC) deployment in Ghawar Field, Saudia Arabia. A well was drilled and completed as a proof of concept. It was set up as a trilateral and was equipped with an SC that encompassed a surface-remotely-controlled hydraulic-tubing-retrievable advanced system coupled with a pressure- and temperature-monitoring system. SC provides isolation and downhole control of commingled production from the laterals. The well was managed to improve and sustain oil production by eliminating water production by use of the variable-positions flow-control valve. Monitoring the rate and the flowing pressure in real time allowed for optimal well production. The appraisal and acceptance portions of the completion process were achieved when this well was completed, put on production, and tested. The concept was approved when the anticipated benefits were realized during monitoring of the performance of the well. Leveraged knowledge from this pilot has provided an insight into SC capabilities and implementation. Moreover, it has set the stage for other developments within Saudi Aramco. Background Haradh forms the southwest portion of the Ghawar oil field, approximately 80 km onshore from the Arabian Gulf, in the Eastern Province of Saudi Arabia (Fig. 1). Haradh field consists of three increments: The initial production started in May 1996 with Increment-1, followed by Increment-2 and -3 in April 2003 and January 2006, respectively. Increment-1 was developed initially by use of mainly vertical wells, while Increment-2 was developed with horizontal wells. The subsequent MRC/ML wells and SC installations in Increment-2 were part of a proof-of-concept project to test and evaluate the impact of these technologies on reservoir and well performance and on overall reservoir-management strategies. As a result of the proof-of-concept project, Increment-3 was developed with MRC/ML wells with SCs. Modeling was used extensively to illustrate the potential benefits of the incremental expenditure of MRC/ML wells with SCs vs. conventional completions (Afaleg et al. 2005; Mubarak et al. 2007). Several authors quantified potential gains from the use of such wells and completions in field developments (Yeten et al. 2002; Saleri et al. 2006). Haradh-A12 is the first MRC/ML well to be equipped with SC in Ghawar field. It was drilled and completed as a trilateral selective producer with a surface-controlled variable multipositional hydraulic system. This paper discusses a closed-loop approach that led to efficient realtime production optimization.