The migration of fines into gravelpacks from both unconsolidated reservoirs and through the injection of fluids from the wellbore, is characterised by permeability reduction which may be gradual or instantaneous depending on the invasion process and the pore blocking mechanism. In an attempt to define the maximum allowable levels of fines that can be tolerated by a typical gravelpack which will ensure optimum production capacity over the economic life of the well, an experimental project on pore blocking mechanisms in gravelpacks was initiated in the Department of Petroleum Engineering at Heriot-Watt University in order to define the gravelpack permeability decline as a function of production time. In this paper, the results of the experimental studies which show the trends of gravelpack permeability reduction as a function of the pore blocking phenomena are presented. Five prevailing pore blocking mechanisms were identified, each characterised by the profile of permeability reduction against time. Based on the characteristic profiles, specific pore blocking mechanism models were developed to quantify gravelpack impairment as a function of gravel-fines size ratio, fines concentration, and fluid production rate. These models have been incorporated into a computerised well performance model which can be utilised to predict both the initial and lifetime performance of a gravelpacked well. Specific case studies, using field data, to illustrate how the well performance model can be utilised to conduct sensitivity analysis of the productivity index to fines concentration, gravel size and production time. Application of the studies to the analysis of gravelpacked well performance especially with respect to maximum allowable level of fines injection during water flooding for injection wells or formation fines production level for specific commercial gravels are presented. The paper also illustrates how the system can be used to predict possible plugging time of a typical gravelpack. Introduction Gravelpacks are installed primarily to control the migration of load-bearing formation sand grains and other fines from unconsolidated reservoirs. The design of the gravelpack is therefore geared primarily towards: prevention of sand migration into the wellbore maximisation of productivity through the use of specially processed pack sands (gravel) minimisation of impairment as a result of particle plugging Achievement of these objectives require the use of rigorously defined criteria in the choice of gravel size. Most gravelpack designs have been geared towards achieving optimum control of sand migration or absolute stoppage with some sacrifice on productivity. P. 29^

Efficient sand control is dependent on the design of the exclusion system and must take into account a number of formation characteristics and production factors which will affect the eventual well performance. For gravelpacking, the design requires the specification of the size of the commercial gravel to use with the final objective being the achievement of maximum productivity over the production life of the well with effective sand exclusion.To date, a number of formulae have been suggested for gravel size selection, the most popular being the Saucier formula. However in a large number of gravelpacks, operators have reported fines being produced in large quantities, suggesting ineffective bridging by the gravelpack.A review of the available gravel sizing formulae show that they may be too general and possibly too simplistic to take full cognisance of the depositional environment of the formation sand, the operational conditions to which the gravelpack is subjected, the reservoir fluid, the gravelpack structure, etc.A project has been initiated in the Department of Petroleum Engineering at Heriot-Watt University to address the problem of determining the optimum gravel size under a range of different operational conditions. The project has the objective of developing a theoretical approach and modelling technique to predict gravel size and also to evaluate particle-pore bridging phenomena, using a series of rigorously defined experiments. This paper presents the results of the comprehensive experimental investigations camed out to evaluate the bridging effectiveness of various commercial gravels as a function of different operational conditions including the sand sorting and shape.The experimental studies were carried out using a purposely-built packed column to evaluate the effects of production rate, fluid type, formation sand and gravel characteristics, absolute and differential pressure on the efficiency of the exclusion treatment.The bridging efficiency of selected gravels were measured. The experimental data generated formed the data base for developing a semi-empirical bridging efficiency equation which assists in the selection of gravel and the prediction of its bridging effectiveness under specified operational conditions. It also allows the design engineer to conduct a sensitivity analysis of the effectiveness of the chosen gravel to a range of variable conditions. The paper concludes with a description of the computer package being developed for optimum gravel size selection. This package is expected not only to select the optimum gravel size but also predict the eventual well performance.

Horizontal drilling of multilateral wells within the last five years has rapidly developed the Saih Rawl Shuaiba reservoir. These wells consist of up to 7 branches, and expose more than 10 km openhole of reservoir per well. Current production of the reservoir is around 8,000 m3/d of oil with an average watercut of 75%. A "produce-the-ultimate"-initiative was followed to systematically analyze, debottleneck and optimize every detail of the production chain: from water injection manifold, water injectors, to oil producers with ESP, including the waterflood efficiency. This has resulted in a range of optimization activities such as ESP changeout, flowline looping, water injector tubing resizing, automation of chokes and an improved water injection distribution system. Initial gains from part of these activities amount to more than 1,000 m3 of oil per day within the first six months. Introduction The Saih Rawl oilfield situated in Central Oman, was discovered in 1971 by SR-2 and came on stream in 1975 (see figure 1). The field is oil-bearing in Shuaiba, Mafraq, Gharif and Al Khlata reservoirs, while gas and condensate are produced from the deeper Amin and Barik intervals. Production started from the most productive Gharif reservoirs. Attempts to produce the Shuaiba reservoir with vertical wells were made from 1984 onwards with three drainholes (SR-16, 20 and 22). However, the tight nature of the reservoir and the thin oil column underlain by water have jeopardized this approach, due to early water production and low initial rates. The development using the conventional vertical well design of that time was not economical. The current Shuaiba reservoir development has started with bare-foot horizontal multilateral wells from mid-1993 onwards. Due to very limited aquifer support, water injection was implemented from end-1994 with horizontal, multilateral barefoot injection wells located below the OWC. To date 50 production and 20 injection wells have been drilled at lateral spacing from initially 250 m to now 60 m. This adds up to more than 172 km of producing and 104 km of injecting drainhole. The current typical well design is a 4 to 7-legged multilateral well with a cased 7"-backbone and 6 1/8" openhole legs. Production wells are completed with ESP and deliver between 1,000 to 3,000 m3/d gross. Apart from drilling new wells, development activities have included side-tracking single horizontal to multilateral producers, restimulating existing wells, isolating a water-cycling leg (in injector well) and converting gas-lifted wells to ESP. The current oil production is around 8,000 m3/d, for a total gross rate of 35,000 m3/d; this represents a field water-cut of 75%. Pressure support is performed at voidage replacement and the reservoir pressure is currently balanced at around 9,000 – 10,000 kPa. Today almost 11 Million m3 of oil have been produced. Currently 38.5 Million m3 are booked as ultimate recovery out of a STOIIP of around 90 Million m3. All Saih Rawl Shuaiba production is routed to the Saih Rawl production station, where it is commingled with gross production from a number of other reservoirs and fields prior to dehydration. The net oil is exported via the Qarn Alam Main Pumping station into the Main Oil Line to the terminal at the coast. The separated gas is compressed; some is recycled as gaslift, the balance being exported. All produced water is currently re-injected into the Shuaiba reservoir, together with additional water from local water supply wells, as required. The separation and dehydration facilities at Saih Rawl Production Station are going to be expanded during the third development phase in Q3-2001. This will result in a "no constraints" facility.

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In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.