Saudi Aramco employed extensive matrix and acid fracturing treatments in thedevelopment of Saudi Arabian non-associated gas carbonate reservoirs.Thetarget reservoir is the Permian Khuff Formation which is the majornon-associated gas reservoir in the prominent Ghawar Field, eastern SaudiArabia.The Khuff reservoir is stratigraphically divided into fourcorrelative zones, namely Khuff-A, B, C, and D in downwardsequence.Khuff-B and C are the two major reservoirs with distinctivehydraulic characteristics. Khuff-A and D zones mostly are either discontinuousor have poor to non reservoir quality. Saudi Aramco is pursuing commingled production selectively as a part of thegas development plan to extend the well's economic life and to meet its growingdomestic gas needs. Since the Khuff-C has better reservoir quality with larger gas reserves, itwas completed by itself during the initial period of the fielddevelopment. Later, the commingled production by adding the Khuff-A and Bhas become part of the overall strategy to offset the natural decline fromKhuff-C and maximize gas production and extend the wells' life. This paper will review the acid fracturing and stimulation practicesemployed by Saudi Aramco in the Khuff-Carbonates. The criteria used to selectsuitable candidates for the commingled production and techniques employed toquantify flow contributions from each individual zone after commingling theproduction will be reviewed. The production performance, lessons learned, business impact and the way forward will be discussed. Introduction Since 1995, Saudi Aramco has embarked on an aggressive non-associated gasreserve development program and gas expansion projects.These projectsencompass the drilling of new wells and developing new reservoirs wherevercommercial gas reserves can be found. Developing the Permian Khuff-Carbonate reservoirs in the prominent GhawarField, eastern Saudi Arabia (Fig. 1) is in the center of this ambitious programto address the ever- increasing domestic energy requirement. Saudi Aramco employed extensively acid fracturing and high rate matrixacidizing stimulations to exploit the Khuff gas reserves. More than 200 Khuffgas wells hydraulic fracturing stimulations have been successfullyemployed. Saudi Aramco is pursuing commingled production selectively as a part of thegas development plan.Through case history examples, this paper will shedlight on the deployed stimulation practices, commingled production results, lessons learned, and business impact.

Drilling horizontal wells, single and multilateral, is nowadays common practice for Saudi Aramco in most of its oil and gas reservoirs (clastics as wells as carbonates) in Saudi Arabian fields. This study highlights the application of a geomechanics study to evaluate well stability drilled into a friable eolian oil-bearing sandstone reservoir. Saudi Aramco's reservoir management was eager to find the optimum mud type and azimuthal direction to place long reach horizontal wells, so as to minimize the risk of stress-induced borehole breakouts, optimize drilling mud weights, aid in making informed decisions about adequate completion design, and ensure sustainable production under depletion mode. The reservoir rocks in this field are characterized as a "wet" eolian depositional system with four distinct depositional facies: dune, sand sheet, paleosol and playa. Grouping the lithology into these four recognizable depositional facies significantly enhanced the understanding of facies dependent rock properties and related wellbore integrity. Hence, a critical objective of the study was to combine the knowledge of reservoir and material properties with detailed analyses of the present day in situ stress field. Upon determination of the in situ stress field in the study area, wellbore stability in the principle horizontal stress directions (Shmin and SHmax) was calculated and compared and the resulting optimum direction was recommended. The effect of mud on rock strength was evaluated and the mud type that caused less rock-strength reduction was selected. The study concluded that under undepleted conditions horizontal wells should be drilled with oil-based mud parallel to the field-derived maximum principal horizontal stress (SHmax) azimuth in order to maximize borehole stability and minimize required mud weights during drilling and completion. The results from this detailed study will be incorporated into Saudi Aramco's reservoir management decision tree, in order to maximize wellbore integrity during drilling and completion such that least damage occurs to the reservoir during drilling and in-gauge hole conditions for successful sand control completion deployment can be maintained. Introduction The structure of the oil field analyzed in this study is a conventional northwest trending asymmetric anticline. The reservoir consists of a Permian well-developed eolian sandstone that is closely associated with inter-dune and lacustrine deposits. The reservoir rocks can be characterized as consolidated, unconsolidated and very heterogeneous sandstone formations with four distinct depositional facies: dune, sand sheet, paleosol and playa. To develop the field to its target production, Saudi Aramco's reservoir management team planned to drill a number of horizontal wells, single and multilaterals to ensure maximum reservoir contact. Most horizontal wells are oriented in an E-W direction. Maintaining wellbore stability while drilling into this friable sandstone reservoir presents a considerable challenge as is the tendency for the sanding of the poorly consolidated portions of the reservoir. Sand production has historically been a problem associated with soft or poorly consolidated formations, which result in lost production due to formation sand and fines plugging; erosion of subsurface and surface facilities, casing and/or well bore collapse. Several methods can be applied to minimize the effect of sand production including critical production rate, gravel packing, sand consolidation, FracPacking, oriented and/or selective perforation, standalone or expandable sand screens (ESSTM). Since Saudi Aramco implemented in the past ESSTM technology successfully in sandstone reservoirs to control sand and improve productivity, this completion strategy was also planned in the study field. The process of expanding ESS has evolved from a fixed diameter using a rigid cone expander into a variable compliant expansion technique to conform to the actual borehole geometry. The compliant expansion technique provides an internal support of the wellbore1. The development team selected ESS and other conventional sand screens as the main completions for all horizontal development wells.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDrilling horizontal wells is a common practice for Saudi ARAMCO in most of its oil and gas reservoirs of Saudi Arabian clastic and carbonate fields. A comprehensive study of rock mechanical properties with detailed analysis of the in-situ stress field was conducted to evaluate well stability during drilling and completion across a friable eolian oil-bearing sandstone reservoir. This paper discusses the application and implementation of the study to successfully drill and complete development horizontal wells in a challenging sandstone reservoir.All horizontal wells were completed with different type of sand screens including Premium and Expandable Sand Screen (ESS). It is vital to obtain a near-gauge hole during drilling for a maximum stability of the screen during the life of a well. It is therefore important to prevent excessive compressive shear failure at the wellbore wall and avoid instability problems during drilling and completion. Therefore, an optimum confining pressure to the wellbore surface needs has been derived. The recommended mud type and weight windows derived from the study have been employed while drilling producers but not with injectors. The correlation between the mud weights and the insitu stress magnitude will be discussed.Well stability during drilling and long term screen integrity is dependant on the well azimuth relative to the in-situ stress field. The azimuth of the maximum horizontal stress, S Hmax, was determined to generally line up in the E-W direction. The wellbore stability problems experienced in this direction as well as those drilled normal to it (i.e., N-S), will be addressed.In regards to stability of very weak and friable formation intervals (such as those encountered in the, dunes and sand sheet facies), the operational practices are focused on creating gauged hole with least erosion effect as a critical measure to deploy the ESS; thus, ensuring successful completion and sustained production. The effect of mud on rock strength was evaluated during the foregoing study; therefore, results from using oil-base mud will be discussed and compared to results from the wells drilled with water-based mud.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe paper presents a case study in which pressure data from wireline formation tester tools, geochemical fingerprinting of hydrocarbon liquids, and comparison of PVT properties has assisted the initial reservoir characterization of a deep gascondensate accumulation in Saudi Arabia. The work has confirmed fluid type, contacts, formation connectivity, and has been a useful complement to conventional seismic and geological data interpretations done for the field. This has been particularly important for this large field which is being fast tracked for development by Saudi Aramco with limited existing well control. The results of the data integration have been instrumental in:Quantifying the extent and connectivity of reservoir units. Assessing reservoir quality for completion design. Constructing geologic and reservoir simulation models for field-development planning.

Defining and distributing petrophysical reservoir property within a simulation ready geocellular model is an industry-wide dilemma; the result of which has a large business impact on reservoir management decisions. The objective of this study is to develop porosity-to-permeability transforms, multiphase relative permeability and capillary pressure curves for each distinct depositional facies. The key to this process is the ability to recognize each of the four eolian facies and demonstrate that even at deep formation; the original depositional facies controls the petrophysical properties. Through core and image-log studies, the geologist divided the reservoir into the four distinct depositional facies that comprise a "wet" eolian depositional system: dune, sand sheet, paleosol, and playa. Each facies was distributed proportionately by zone (vertically) and by region (area) in a 3D geocellular model using an object based modeling technique and a wet eolian depositional model. The dune facies is the best reservoir unit followed by sand sheet; together the dune and sand sheet comprise a high proportion of the reservoir gross thickness. Conventional and special core analysis measurements were conducted on hundreds of core samples from three gas wells. The core data were thoroughly evaluated for pertophysical properties, and then grouped by depositional facies. Porosity-to-permeability transforms, multiphase dynamic relative permeability and capillary pressure were derived for each facies. The reservoir properties were then geostatistically distributed within each facies object using the facies and zone specific transforms. Results showed a quantifiable porosity-to-permeability transform, and corresponding capillary pressure and condensate-gas relative permeability for each depositional facies in the reservoir. This paper shows that by grouping the reservoir into recognizable depositional faceis has significantly enhanced the distribution of reservoir and fluid properties, which were incorporated into a compositional model. This will result in a dependable fluid-flow model that will support investment, reservoir development and reservoir management decisions. Introduction Saudi Aramco has conducted a successful integrated study to fast track develop a large, rich gas-condensate field located south of Ghawar in Saudi Arabia. The main goal of the study was to establish reliable rock and fluid properties to characterize a deep eolian sandstone reservoir composed of four distinct depositional facies. The Unayzah-A reservoir is Permian in age and consists of well-developed eolian sandstones and associated inter-dune and lacustrine deposits. Based on thorough and extensive geological assessment, geologists have divided the reservoir into four discrete geologic facies: dune, sand sheet, paleosol, and playa. The best reservoir units are observed in the dunes followed by sand sheets throughout the field. (MDT) Pressures, core, and log data1 indicated that dunes and sand sheet in the Upper Unayzah A are more permeable than the thick Main Unayzah A unit due to the clay choking effect in the main Unayzah A. The paleosl and playa contains low reservoir quality rocks, low porosity, and very low permeability (<1 md), thus they are considered as non-reservoir and act as baffles and barriers that separate flow units. The study has utilized conventional and special core analysis conducted on three development wells drilled throughout the south and north margins of the field. To reduce the uncertainties, the core data were thoroughly evaluated and then were grouped by the depositional facies. Consequently, an engineering process was conducted to generate permeability-porosity transforms and multiphase dynamic relative permeability and capillary pressure for each facies. These rock and multi-phase fluid properties data proved to build a robust reservoir compositional simulation model. The resulting data were analyzed and integrated with geological and log interpretations to allow a more reliable characterization of the pay interval into flow units for completion design and reservoir modeling.