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]
Gas condensate reservoirs experience significant productivity losses as reservoir pressure drops below the dewpoint due to condensate accumulation and the subsequent reduction in gas relative permeability. One potential way to overcome this problem is to alter reservoir wettability to gas-wetting to reduce condensate accumulation in the near-wellbore and maintain high productivity. The aim of this study was to evaluate the effectiveness of various chemical treatments in altering wettability of gas-condensate reservoirs from liquid wetting to intermediate gas wetting. Coreflood experiments were conducted on carbonate and sandstone reservoir cores and Berea cores at simulated reservoir conditions. Several chemicals (fluorochemical and silane) were screened in this study to determine their capability in removing the trapped condensate from cores, enhancing gas relative permeability, and delaying condensate accumulation. The results of coreflood tests showed that the effectiveness of fluorochemical surfactant is affected by treatment volume, aging time, core permeability and temperature. Sandstone cores treated with 1.25 wt% silane chemical showed repellency to liquids (water and condensate) and an enhancement (up to 42%) in gas relative permeability. It was found that core permeability plays a role in wettability alteration agents' effectiveness. Wettability tests showed that contact angle on treated cores is 116° for water and 114° for condensate, indicating wettability alteration from liquid to intermediate gas wetting. Environmental Scanning Electron Microscope (ESEM) analysis performed on silanes-treated cores gave a conclusive evidence of wettability alteration at the pore scale. Introduction Maintaining production from gas reservoirs is a challenge due to the dropout of condensate and accumulation in the near wellbore region when the bottom hole flowing pressure decreases below the dewpoint pressure. Condensate flows along with the gas phase in the reservoir only when its saturation reaches or exceeds the critical condensate saturation. Gas well productivity starts to decline as condensate bank forms around the wellbore area. Without pressure maintenance (for example, gas cycling), condensate banking cannot be prevented. It may be delayed by using the proper exploitation methods, such as fracturing and horizontal completion.1–7 Condensate can be mobilized from the near wellbore region by either reducing capillary pressure or increasing drawdown pressure (viscous forces). Capillary pressure can be reduced by either decreasing the interfacial tension, wettability alteration. Solvents have been used to remove condensate banking from gas wells by decreasing interfacial tension and increasing liquid vaporization rate, but their effectiveness is temporary due to solvent flowback.8,9 Since most of reservoirs are preferential liquid wet, altering their wettability using chemical treatments to intermediate or gas wet reduces condensate entrapment and helps to maintain or increase gas production. Achieving this objective, chemicals are required to have certain properties such as longevity, non-damaging, thermally stable and low cost.
Near-wellbore formation damage is expected during the drilling operations. Minimization, prevention, and removal of near-wellbore damage are essential to maximize well productivity. One of the major sources of skin damage is the residual filter cake developed by reservoir drill-in fluid (DIF). Therefore, an efficient filter cake cleanup method should be considered to enhance well productivity. Oil producers in sandstone reservoirs are being drilled with invert emulsion DIF during oil reservoir drilling. Standard completion of oil wells is with stand-alone screens. Although screens stabilize the wellbore and address sand control issues, it can also act as a trap for filter cake, resulting in high drawdown pressure. An in-situ acid-precursor technology, which generates organic acid, was proposed to be used. The prime advantage of this technology, especially in long horizontal wells, is the uniform distribution of acid during precursor to remove oil-based mud (OBM) filter cake by a single-stage. A special surfactant blend was incorporated in the cleanup fluid to alter the wettablity of the oily filter cake, and therefore, facilitate the reactivity of the produced acid with calcium carbonate particles. Detailed lab studies were conducted to evaluate the efficiency of the in-situ acid generator technology. The lab studies include various tests to evaluate filter cake removal efficiency, return permeability on real core samples, compatibility with formation fluids, and strength of dissolving calcium carbonate particles. Based on lab results, it was recommended to spot the single-stage filter cake cleanup fluid as a treatment for an oil well. This paper will discuss in detail the laboratory work that was conducted to evaluate the filter cake cleanup fluid performance. Introduction Minimization and removal of formation damage is an ultimate goal in drilling and completion designs to reach the target production rate. Field practices and numerous case studies have shown that near-wellbore damage is mainly caused by the drill-in fluid (DIF), which may result in major production restriction. The damage is caused by a form of external damage, such as mud cake. Invasion of mud solids and filtrate is a major source of the near wellbore damage (Almond et al., 1995; Leschi et al., 2006). The conventional near-wellbore damage removal or filter cake cleanup methods by chemical means are enzymes, chelating agents, reactive mineral acids, oxidizers, or a combination of these chemicals (Davis et al., 2004; Davidson, E. et al., 2006; Al-Otaibi et al., 2004). When it comes to removing an oil-based mud (OBM) filter cake, prior stages should be considered to these conventional treatments. The wettability of the oily filter cake particles must be altered from oil-wet to water-wet. This is usually done through multi-stages and consumption of large volumes of solvents, mutual solvents, and surfactants mixed in a carrying fluid. Eventually, for an operator, completing a well drilled with an OBM will be time-consuming and expensive using the mentioned conventional treatments.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe objectives of this study were to: investigate effectiveness of alcoholic acids to stimulate Devonian sandstone gas reservoirs, determine the optimum acid formulation, and recommend the best practices to enhance stimulation treatments in gas wells. In this study, extensive coreflood experiments were conducted on sandstone cores recovered from gas reservoirs to assess the effectiveness of various acid formulations (HCl, HCOOH, HCl/HF, and HCOOH/HF, with and without alcohols) in enhancing gas relative permeability. Several solvents and chemical additives were evaluated to remove or reduce trapped liquids. Experimental results showed commonly used completion fluids caused a severe reduction in gas relative permeability. This study indicated that alcohols can be mixed with stimulation fluid to expedite the cleanup of spent acid and help to attain maximum gas well potential directly after stimulation treatment.Experimental results showed that alcoholic acids have a slower reaction rate with rocks compared to conventional acids having the same acidity. Alcoholic acids can be injected deeper into the formation and their corrosivity can be reduced in hot deep wells with a proper use of corrosion inhibitor type and concentration. Because of low IFT of alcoholic acids, they can be easily injected into tight formation when there are limitations in injection pressure and resulted in deeper stimulation than with conventional acids. This paper discusses a case study on damage diagnosis for a gas well which was recently completed and showed unexpected low productivity. This study proposed an effective stimulation formulation for gas wells and better practices for stimulation design to reduce flowback time needed to lift spent acid and help to achieve maximum production.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.