Chirag field was the first of three fields put into production in the Azeri -Chirag -Guneshli (ACG) megastructure, located in the Azeri sector of the Caspian Sea and operated by BP on behalf of Azerbaijan International Operating Company (AIOC). Production commenced in late 1997 after completion of the Chirag A01T1 well. A number of different sandface completion types have been installed in Chirag injectors and producers during the Chirag Early Oil Project (EOP), and significant data have been collected to evaluate the performance of each completion type. Completion types include cased and perforated, open hole gravel packs (OHGP) using wire-wrapped, pre-packed and alternate path (shunttube) screen technology, stand-alone porous metal fiber premium screens, and expandable screens. To date, 29 completions have been installed in 19 of 24 available well slots in primary and sidetrack wells.Many of the producing wells are equipped with permanent downhole pressure-temperature gauges, the flowlines are equipped with acoustic sand detection devices, and an active separator production test and surveillance program has resulted in a quality data set to evaluate completion performance under initial "dry oil" (water free) conditions, and upon the onset of produced water. This quality data set has greatly assisted the completions performance analysis, which has helped shape completion decisions and technology requirements for full field development.The paper will review the completion evolution in Chirag field, the relative performance of completion types over a broad range of indicators, and will include a discussion about measures taken to improve open-hole gravel pack performance from a reservoir damage perspective, with a focus on producers.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMany of the recently discovered reservoirs in deepwater/subsea environments are prime candidates for horizontal open-hole gravel packs. Presence of multiple reactive shale breaks and penetration of different sand bodies along these holes introduce a formidable challenge for selection of proper carrier fluids, considering that most of these wells require oilbased (OB) drilling fluids.Various procedures were practiced for gravel-packing wells drilled with OB fluids, most utilizing water-based (WB) carrier fluids. Primary concern in using WB carrier fluids is the destabilization of the shales.If the displacements to WB fluids are performed prior to running in hole with the sandface completion assembly, inability to run the screen assembly to target zone is the risk. Consequently, operators were forced to use a two-step process, whereby a predrilled liner is run in hole in OB fluid environment, followed by displacements to WB fluids and gravel-packing with WB fluids. This approach introduces additional rig time and increases completion costs.If the displacements to WB fluids are performed after running in hole with completion assembly, primary challenge is the prevention of screen plugging. This necessitates a comparison of the benefits and risks of displacements to solids-free oil-based fluids and conditioning of the OB drilling fluid, considering logistics.An additional consideration in gravel packing with WB fluids in reactive-shale environments is the risk of intermixing of gravel with shales, thus reduced gravel-pack permeability. Various approaches may be taken to minimize this risk. The type of carrier fluid must also be kept in mind from a formation and gravel pack damage standpoints, should losses be experienced during gravel packing.Another approach in reactive shale environments is to use an oil-based carrier fluid and avoid exposure of the open hole to WB fluids both prior to and during gravel packing. This approach, practiced in two applications, also has its limitations.In this paper, a critical review of gravel-packing practices in oil-based drilling environments is provided, along with some of the recent developments and recommendations for future applications based on lessons learned from earlier practices.

Summary An increasing number of horizontal wells requiring sand control are being gravel packed, particularly in deepwater and/or subsea environments in which completion reliability is paramount because of the prohibitively high cost of remediation. Tophole sections in many of these wells are being drilled with oil-based (OB) fluids, with the common practice of switching to water-based fluids when the reservoir drilling starts. In the last several years, some operators started using OB drilling fluids in the reservoir section as well and gravel packed them with water-based fluids. In some cases, these practices required running predrilled liners in OB fluids and subsequently displacing to water-based fluids before running in hole with the sandface screens and gravel packing. In other instances, screens could be run in hole with OB fluids in the wellbore, and gravel packing could be performed with water-based fluids. In both cases, the presence of reactive shales and/or water-sensitive productive zones can introduce serious concern, in the event that carrier-fluid losses occur into the formation during gravel packing. Although a base-oil or diesel can be used as a carrier fluid, low density of the base oil limits such applications to low-pressure/depleted wells. In this paper, we present a case history of the first successful application of drilling and completing in an all-oil environment, using a reversible OB reservoir-drilling fluid (RDF) (the filter cake of which reverses wettability from oil to water when exposed to an acidic fluid) and an OB gravel-packing fluid. The carrier fluid used in this application included a filter-cake cleanup solution in the aqueous internal phase of the OB carrier fluid, extending the application of simultaneous gravel-packing and cake-cleanup processes that have been successfully practiced in water-based-fluid environments to OB systems. The subject application was in a high-rate gas field located offshore Trinidad, with anticipated production rates in excess of 150 MM scf/D per well. Presented in the paper is the drilling and completion selection methodology based on extensive laboratory and yard testing, along with the details of the completion and recommendations for future applications based on lessons learned. A direct comparison of the all-oil drilling and completion process to water-based drilling and completion is also presented based on a case history from the same field. Introduction Openhole gravel packing is a proven sand-control technique from both productivity and reliability standpoints and has been the preferred method of sand control by many operators in deepwater/subsea developments (Price-Smith et al. 2003; Ali et al. 2001). Synthetic/oil-based (S/OB) fluids have traditionally been the preferred drilling fluids in these environments, although the operators have often been forced to switch from S/OB mud used to drill the tophole to a water-based fluid for reservoir drilling because of various concerns, particularly in wells that will be gravel packed. The drivers for S/OB drilling have been well documented and include a higher rate of penetration, excellent shale-inhibition characteristics unmatched by any commercially available water-based fluid, gauge hole, lubrication while drilling as well as while installing sandface completion, low maintenance costs (dilution and solids-control costs in reactive silt/shale environments), and so on (Gilchrist et al. 1998). In addition, switching to an S/OB RDF is much less time consuming and simplifies fluid management at the surface (intermixing of water-based and OB fluids vs. two OB fluids, storage space on the rig, etc.).

Laboratory reservoir conditions flood tests were used to determine the clean up efficiency of a drilling mud that was applied at two different overbalance pressures. The test was designed to simulate, as closely as possible, the conditions occurring in the reservoir during the drilling operation. Relevant core material was used and the pore/overburden pressures, mud overbalance pressures, temperature and production drawdown pressures/rates applicable to field conditions were applied in the laboratory simulation. Drilling mud filtrate volume loss versus time measurements were made at reservoir conditions using sophisticated pumps. All wetted parts of the rig were constructed of hastelloy C276 alloy to avoid corrosion artifacts interfering with the test. Permeability measurements were made prior to mud application and again at the end of the flood test analysis to determine the level of any formation damage. In order to determine the nature of the formation damage mechanisms, geological techniques which included dry and cryogenic SEM and thin section analyses were undertaken. These techniques were applied to the plug trims prior to testing (untreated samples) to determine the natural state of the rock, paying particular attention to the clay mineral and cement types, morphologies and distributions. The plug samples were examined at the end of testing (treated samples) and any variations noted which would highlight the damage mechanisms. The dry SEM and thin section analyses were used to determine solid damage mechanisms such as clay fines migration, scale precipitation and drilling mud solids invasion. The cryogenic SEM analyses were used to examine any fluid damage mechanisms such as wettablity alteration, microemulsion formation, water/oil blocks or fluid retention. A new technique of cryogenic SEM using EDX (Energy Dispersive X-Ray) analysis was used for X-ray mapping of the remnant mud bodies to determine solid and fluid distributions. Introduction The objective of the laboratory analysis performed was to determine the effect of high over balance during drilling followed by simulated return to production on the productivity from a particular lithology in an oil well. Any damage mechanisms and there impact on productivity were to be fully investigated and implications for future drilling and completion highlighted. A series of reservoir conditions core flood tests were designed to measure the permeability changes caused by different well conditions1. The core flood tests were designed to simulate as closely as possible the real wellbore conditions. Thorough sample evaluation was used to identify all damage mechanisms and reasons for measured permeability changes. Combinations of standard and innovative sample evaluation techniques were used to examine the core plug samples after the flood tests and the external bodies developed during mud application and remaining after simulated return to production. Core Flood Test Procedures Sample Selection and Preparation. A total of six one inch diameter core plug samples were cut from a wax preserved whole core sample. The plug samples were cleaned using a warm submerged soxhlet cleaning technique and dried in a 60°C dry oven. End face debris caused during trimming of the plug samples was removed using the acetate peel technique2. Base parameters of porosity, permeability and grain density were measured. The plug samples were C. T. scanned in order to view any heterogeneity or anomalies which might adversely affect the core flood testing. Three samples were selected to be representative of the target lithology and with relatively similar base parameters. The three samples were initially saturated 100% to simulated formation water (see below) and then spun to irreducible formation water saturation using an ultracentrifuge. The ultracentrifuge technique is used in order to obtain a consistent, repeatable saturation relatively quickly without mobilising fines within the plug samples. Sample Selection and Preparation. A total of six one inch diameter core plug samples were cut from a wax preserved whole core sample. The plug samples were cleaned using a warm submerged soxhlet cleaning technique and dried in a 60°C dry oven. End face debris caused during trimming of the plug samples was removed using the acetate peel technique2. Base parameters of porosity, permeability and grain density were measured. The plug samples were C.T. scanned in order to view any heterogeneity or anomalies which might adversely affect the core flood testing. Three samples were selected to be representative of the target lithology and with relatively similar base parameters. The three samples were initially saturated 100% to simulated formation water (see below) and then spun to irreducible formation water saturation using an ultracentrifuge. The ultracentrifuge technique is used in order to obtain a consistent, repeatable saturation relatively quickly without mobilising fines within the plug samples.

Summary Many of the problems associated with the use of water-based fluids in drilling and completion operations are caused by incompatibilities between the fluids and the shales. Such incompatibilities may result in washouts, increased drilling costs (e.g., solids handling, rig time, dilution fluids), and shale sloughing during the drilling operation and after displacements to completion fluids or during gravel packing. One of the most important factors leading to an undesired result (either a premature screenout, thus a potential sand-control failure, or a higher skin) in water-packing of open holes is the presence of reactive shales in the interval to be gravel packed. Although there is a substantial amount of literature on shale inhibition with water-based drilling fluids, the importance of shale inhibition and the problems associated with shale reactivity during gravel packing remain largely unexplored. Furthermore, shale-inhibitor selection often relies on a comparison of the results from bottle-roll tests using shale samples in candidate fluid/inhibitor pairs (drilling or completion fluid) and on tests measuring the degree of shale swelling. While these tests are highly functional, they can provide information only on the relative performance of fluids, and their relevance to gravel packing is questionable because these tests do not simulate the conditions experienced during such treatments. This paper presents guidelines on selection methodology of shale inhibitors for use in gravel-packing applications on the basis of the data available in our respective companies, including a comparison of results from conventional bottle-roll tests to those from flow through predrilled holes in shale core samples. Recommendations are made depending on brine type and density, type of shale, temperature, fluid exposure history, and environmental considerations. Introduction Openhole-horizontal completions have emerged as a cost-effective means of exploiting deepwater reservoirs, many of which require sand control. Gravel packing is the preferred sand-control technique for such environments where remedial treatment costs are prohibitively high (Price-Smith et al. 2003). Two techniques have been employed for gravel packing open holes with varying degrees of success: alternative path and water packing. The focus of this paper will be to address one of the problems considered to be a key risk factor in successful implementation of water-pack treatments. The risks associated with openhole water packing completions can be summarized asSwabbing, which has been addressed through the development of antiswab-tool systems (Vozniak et al. 2001)Exceeding fracturing pressure--during the beta-wave, which has been addressed with the development of beta wave attenuators (Coronado and Corbett 2001) or use of low-density gravel, allowing lower pump rates without the concern for gravel settling in the work string (Pedroso et al. 2005)--during the alpha wave in environments with narrow-frac window, that in some cases may be addressed through the use of low-density gravel (Pedroso et al. 2005)Filter-cake erosion, (the conditions under which this becomes a risk remain to be determined) (Gilchrist et al. 1998)Reactive shales that may either collapse/slough or disperse in the carrier fluid; the former may lead to a premature screenout because of blockage of the annulus, and the latter may result in a low-permeability gravel pack because of shale and gravel intermixing (Gilchrist et al. 1998; Corbett and Winton 2002; Mathis et al. 2000; Murray et al. 2003) Shales are characterized by high clay content, low quartz content, and low permeability (a byproduct of the small-clay size). On the basis of numerous factors, shale can react catastrophically when exposed to some aqueous fluids. These factors include downhole-stress states, native-fluid composition, mineralogical composition, and interaction with the completion-fluid chemistry and properties. It is important to note that these factors also determine the time a shale will take to fail when exposed to a given completion fluid, and hence, a shale that has survived the drilling process may still fail during the post drilling activities leading to the gravel pack (Dickerson et al. 2003). It is possible to minimize and even eliminate this adverse reaction by selecting a suitable completion fluid. This selection may involve choosing the correct brine type and additives to increase the inhibitive qualities of the completion fluid. The literature on the subject of shale compatibility with muds is vast. The reactivity of shales to aqueous muds with various additives has been well studied (Chenevert 1970; O'Brien and Chenevert 1973; van Oort 1997). However, the effect of completion fluids has not been studied extensively. The purpose of ensuring proper shale inhibition with drilling mud is to address shale reactivity concerns such as cuttings disintegration, wellbore instability during drilling, and bit balling (van Oort 1997). On the other hand, a completion fluid must be formulated to inhibit shale to maintain wellbore stability after drilling (e.g., during mud displacements or gravel packing) in reactive-shale sections (Gilchrist et al. 1998; Mathis et al. 2000) and to prevent erosion of weakened shales during gravel packing (Ali et al. 1999). Various testing techniques have been proposed in the literature to characterize the inhibitive properties of drilling fluids (Roehl and Hackett 1982; RP 131 2004; Bailey et al. 1994; Mondshine 1973). Because these tests were designed specifically for drilling applications, their direct applicability to water packing, subsequent to water-based drilling, is questionable. Of these testing techniques, the wellbore-simulator tests first described by Darley (1969) and further developed by Bailey (1994) and Gaylord (1983) are more useful for evaluating inhibitor effectiveness in gravel-pack applications, as is also suggested by Corbett and Winton (2002). By exposing various fluids to boreholes drilled in shale cores, Darley (1969) showed the different modes of failure and correlated them to the effect of tectonic stresses, mineral content, age of shales, and flow of mud through the shale borehole. Gaylord developed this testing to look further at the effect of fluid-mechanical parameters on borehole erosion and concluded that erosion will be most pronounced if the particular shale/fluid system is reactive. In addition, hole erosion increases with increasing shear stress and is exacerbated under turbulent conditions. The tests done by Bailey (Price-Smith et al. 2003) look only at the effects of reactivity by shale but corroborate the mechanism of weakening of the shale and subsequent erosion by flow. This is evident in their tests through increased wellbore diameter resulting from erosion. On the basis of this information, a similar test will be used in this work to evaluate completion-brine inhibition. It is the objective of this paper to provide guidelines on selection methodology of shale inhibitors for use in gravel-packing applications. The paper is organized as follows. First, a brief description of the typical critical stages in a gravel-packed completion is given. This is followed by a discussion of the current testing methodology typically employed in the industry. Next, the experimental techniques and materials used in this study are presented, followed by the results from hot-roll and drilled-core experiments. Finally, conclusions are drawn.

fax 01-972-952-9435. AbstractAn increasing number of horizontal wells requiring sand control are being gravel packed, particularly in deep-water and/or sub-sea environments, where completion reliability is paramount due to prohibitively high cost of remediation. Tophole sections in many of these wells are being drilled with oilbased fluids, with the common practice of switching to waterbased fluids when the reservoir drilling starts. In the last several years, some operators started using oil-based drilling fluids in the reservoir section as well, and gravel packed them with water-based fluids. In some cases, these practices required running pre-drilled liners in oil-based fluids, and subsequently displacing to water-based fluids, prior to running in hole with the sand-face screens and gravel packing. In other instances, screens could be run in hole with oil-based fluids in the wellbore, and gravel packing could be performed with water-based fluids. In both cases, the presence of reactive shales and/or water-sensitive productive zone can introduce serious concern in the event that the carrier fluid losses occur into the formation during gravel packing. Although a base-oil or diesel can be used as a carrier fluid, low density of the base oil limits such applications to low-pressure/depleted wells.In this paper, we present a case history of the first successful application of drilling and completing in an all oil environment, utilizing a reversible oil-based reservoir drilling fluid and an oil-based gravel packing fluid. The carrier fluid used in this application included a filtercake cleanup solution in the aqueous internal phase of the oil-based carrier fluid, extending the application of simultaneous gravel packing and cake cleanup processes that have been successfully practiced in water-based fluid environments, to oil-based systems. The subject application was in a high-rate gas field located offshore Trinidad, with anticipated production rates in excess of 150 MMSCFD per well. Presented in the paper is the drilling and completion selection methodology based on extensive laboratory and yard testing, along with the details of the completion and recommendations for future applications based on lessons learned. A direct comparison of the all-oil drilling and completion process to water-based drilling and completion is also presented based on a case history from the same field.

Initial Open Hole Gravel Pack (OHGP) completions that have been installed in Greater Plutonio to date have all achieved complete annular packs and zero mechanical skin factors, resulting in well productivity indices that are significantly greater than expected. The success of the Greater Plutonio OHGP completions has been attributed primarily to the rigorous design and field application of the fluid systems used at all stages of the well from drilling the reservoir through to the gravel pack itself and subsequent completion. An integrated approach was adopted for the design of the fluid systems involving extensive formation damage and fluid compatibility testing. To translate the robust design into a fluid system which can be applied effectively in the field, a thorough, fit for purpose QA/QC system for all drilling and completion fluids was developed, requiring extensive fluids testing and reporting at the well site. The paper describes in detail the reservoir completion philosophy, drilling and completion fluids' systems and overall operational practices used in the Greater Plutonio OHGP completions. It also discusses the fluids design phase of the project and the QA/QC processes implemented in the field. Finally the paper presents the well productivity data from the wells completed to date. Introduction The Greater Plutonio Development is a 5 field deepwater project, located in Block 18, offshore Angola (Figure 1). All 43 planned development wells are subsea in water depths ranging from 1200 to 1500m. Of the 43 wells, 20 are producers and 23 are injectors. The development drilling programme began in 2005 with the aim of drilling and completing 15 wells prior to first oil in 2007. All the 5 fields produce from poorly consolidated Oligocene, turbidite reservoirs and consequently sand control is required in all development wells. Each of the 5 fields is composed of multiple stacked reservoirs separated by shales. The formation sands are high permeability (Kaverage between 800 to 1500md) with low viscosity oil (0.5 to 0.8 cP). GOR ranges from 700 to 1100 scf/stb. Formation Sand Particle Size Distribution Laser Particle Size (LPSA) and sieve analysis was performed on the whole core recovered from the exploration and appraisal wells. The results of the analysis conducted on these wells are summarized in Table 1. These results are typical of all producing formations in the Greater Plutonio Development. The LPSA data for the main reservoir, the Plutonio O73, are shown in Figure 2. The majority of the sands are well sorted with low fines content. There are however some poorly sorted sands with higher fines content which result in the Uniformity Coefficient (D40/D90) ranging from 2 to 16 and the fines content from 1 to 15%. Overall the formation sands are poor to well sorted with low to high fines content. This particle size distribution data (PSD) combined with the limited amount of whole core data available for 5 fields, required the selection of a sand control system capable of providing well bore stabilization in all production wells. Shale Characteristics The deepwater Angola fields are located in shallow, immature sediments which typically have reactive shales that are incompatible with water based fluids. The experiences from the analogue fields in the basin clearly demonstrate the reactivity of the shales. The initial Open Hole Gravel Pack (OHGP) wells in an offset Angola deepwater block, were drilled with oil based mud and the hole was displaced to brine prior to running screens 1. Significant problems were initially encountered running screens due to shale instability and as a result the current system in the offset block deploys the screens in oil based mud.

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