Coreflood experiments were conducted on carbonate and sandstone cores from gas-condensate reservoirs in Saudi Arabia to assess the loss in gas relative permeability caused by condensate accumulation and water blockage. Field samples of condensate were used in these experiments to mimic twophase flow around the wellbore region when the bottom hole flowing pressure dropped below the dewpoint. The impact of several fluids used as completion fluids was also investigated at reservoir conditions. Several solvents were evaluated to remove both condensate and water blockages. Experimental results show that reductions of 70% to 95% in gas relative permeability were seen in reservoir cores due to condensate blockage. The studied solvents were found to be effective for enhancing gas relative permeability. This study also quantified the required methanol treatment volumes to increase gas relative permeability at lab conditions, which could be extrapolated to field conditions. The reduction in gas relative permeability was more pronounced during two-phase flow in the presence of water saturation due to the dual effect of condensate and water blockage. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period. Methanol-water mixtures were ineffective in removing condensate blockage and decreased gas productivity after their treatment. Methanol was effective in removing water from the cores. A mixture of isopropyl alcohol and methanol yielded similar favorable results as pure methanol. In summary, the evaluated solvents were all effective in removing condensate blockage from the core, delayed condensate accumulation, and enhanced gas productivity. Introduction Gas production from reservoirs flowing at bottom hole pressure lower than the dewpoint pressure, precipitates the accumulation of a liquid condensate in the near wellbore region. This condensate accumulation, also referred to as condensate banking, reduces the gas relative permeability and thus the well's productivity. Condensate saturations in the near wellbore region can reach as high as 50–60% under pseudo steady-state flow conditions.[1] Even when the gas is very lean, such as in the Arun field, with a maximum liquid drop out of 1.1%, condensate banking can cause a drastic decline in well productivity.[2–4] The Cal Canal field in California showed a very poor recovery of 10% of the original gas-in-place, because of the dual effect of condensate banking and high water saturation.[5] Several methods have been proposed to restore gas production rates after a decline due to condensate and/or water blocking.[6–9] Gas cycling has been used to maintain reservoir pressure above the dewpoint. Injection of dry gas into a retrograde gas-condensate reservoir vaporizes condensate and increases its dewpoint pressure.8 Injection of propane was experimentally found to decrease the dewpoint and vaporize condensate more efficiently than carbon dioxide.[10] Hydraulic fracturing has been used to enhance gas productivity, but is not always feasible or cost-effective.[5,11] Hydraulic fracturing is a commonly used technique to restore the gas productivity of wells in which the flowing bottom hole pressure has dropped below the dewpoint.[12] High water saturation in the formation after a stimulation or workover treatment reduces the gas relative permeability. The adverse effect of condensate banking increases in the presence of high water saturation. A water block may occur when capillary forces exceed formation gas pressure. Under this scenario, water remains in the reservoir and it is flowed back at a very low rate. There are numerous examples of wells that required long periods of time to restore the initial gas productivity following liquid injection into the formation. The negative impact of water blockage increases in low permeability formations where the capillary forces are high or in low pressure reservoirs.[6,11,13]

The first phase of an accelerated project to develop Saudi Arabia's deep gas potential has been sanctioned, and a large number of new gas producers are currently being drilled and completed. A number of wells have been either acid or hydraulically frac'd, and preliminary production tests have shown significant productivity increases resulting from this type of stimulation. Consequently, plans have been finalized to frac most existing and future wells in this development.

TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract

Acid fracturing has been an integral part of Aramco's gas development strategy for the vertical wells in the Khuff carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. During acid fracturing, the wormholes created by the reaction, results in excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid, a polymer-based system, are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad.These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest reservoir quality zones with minimal contribution from the other zones in many cases.A pilot involving the use of a new degradable fiber technology designed to achieve effective acid diversion during acid fracturing was recently implemented. The pilot comprised field trials in a number of wells with similar reservoir characteristics and multiple porosity lobes. The fracturing treatments were designed and pumped with alternating stages of acid and fiber-laden polymer based pad fluid. The significant viscosity increase achieved in the pad by the addition of fibers and its particulate bridging mechanism would plug off the just stimulated zones effectively, thus diverting the new stage of acid into the non-stimulated porous zones. These fibers degrade and hydrolyze with temperature and time thus leaving the reservoir undamaged. This paper discusses the planning and design processes leading to the successful implementation of the technology, the experience during the stimulation treatment execution and the excellent post-stimulation results. Bottomhole pressure gauge data and production logs were run on these wells to ascertain the effectiveness of the technology and the results are discussed in the paper along with production history comparisons with offset conventionally acid fractured wells, and the lessons learned throughout the pilot.

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