Drill-in fluids contain biopolymers such as xanthan gum, cellulose, and/or starch, along with bridging agents like sized calcium carbonate particles. These polymers are used to enhance the carrying capacity of the mud and to form a filter cake to minimize leakoff of the drilling fluids into the formation.Proper removal of drilling-mud filter cake is essential to minimize formation damage. The damage becomes more intense in tight formations, especially in horizontal gas wells in which the drawdown is not high enough to dislodge the filter cake. Another source of damage is the mud filtrate where fines migration and water blockage can occur in tight formations, especially in sandstone reservoirs.A thorough laboratory investigation of formation damage induced by drill-in fluids (water-based) was conducted. A mini-flow loop was used to assess formation damage induced by polymers present in the drill-in fluid. Various cleaning fluids were examined and their effectiveness in removing the filter cake was determined. These fluids included acidic brines, surfactants, mutual solvents, specific enzymes, and combinations of these fluids. The retained permeability of reservoir cores was determined for each cleaning system. This paper presents results obtained from the laboratory and recommendations made to remove drilling-mud filter cake from horizontal gas wells in a deep sandstone-gas reservoir.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMany soft sandstone formations are completed with horizontal wellbore. The drilling fluid, water based mud, filter cake is left in place until the completion operations are finished. At that time, a cleanup fluid is pumped to remove the filter cake deposition from the wellbore face. These cleanup fluids can be acid, specific enzymes, oxidizers or acidic water. Reservoir heterogeneity complicates the cleaning process. There is a need for a slow, efficient method to remove filter cake, without affecting the integrity of the formation. In this paper, a comparison of various cleaning methods was conducted in the lab (using ceramic disks, core plugs) and in the field. Chemical analysis for core effluent and well flowback samples after various treatments was conducted. These tests included: Anthrone method for carbohydrates, and full analysis of the produced solids using acid solubility, XRD, and SEM.
Water based drill-in fluids usually contain starch and xanthan polymers and sized calcium carbonate particles, which help in developing an effective filter cake during drilling process to control fluid loss. Proper removal of the drill-in fluid filter cake from the pay zone is essential to maximize productivity. The latest technique for filter cake clean-up is the application of acid and enzymes in a single stage. The prime advantage of this technique is the uniform placement of acid through precursor in long horizontal wells. Other benefits include: cost and time saving by avoiding multistage treatment and reduced risk of tools corrosion, which is associated with mineral acids. A detailed study was conducted to evaluate the efficiency of acid-precursor-enzyme system to be used in multi-lateral, maximum reservoir contact wells. The evaluation was performed by using samples of polymer based drill-in fluids and dry bulk of sized calcium carbonate in terms of return permeability determination, change in particle size distribution, and weight loss. Results indicated that the generated acid mainly targeted fine particles of calcium carbonate present in drill-in fluids and dry bulk. This paper presents results of lab investigations and merits (or demerits) of single stage treatments. Introduction The acid-precursor-enzyme system (APES) is a wellbore cleaning chemical. It is composed of ingredients including enzymes and acid-precursor and designed to act in two ways: to degrade the polymer present in the filter cake by enzymatic action and to dissolve calcium carbonate by acid generated in-situ. The basis of the process is that an acid precursor compound is mixed in brine, where the acid is generated over a period of time and reacts with calcium carbonate, while substrate specific enzymes simultaneously act on polymers like starch and xanthan. The enzyme-based process of generating acid in-situ and filter cake removal in a single stage has been studied.[1–3] The present investigation is an attempt to examine the merits and limitations of APES in maximum reservoir contact (MRC) wells. In the recent years, with the shift from vertical and horizontal wells to MRC well types, the longer horizontal hole section have become more challenging to clean-up as access to the pay zone with coiled tubing is becoming more expensive and in some cases difficult. Hence a filter cake clean-up system was required to clean the pay zone by using drill string immediate after drilling. DIFs with reasonable properties and favorable particle size distribution (PSD) were designed to meet the challenging task of MRC drilling. MRC wells have proved their success as a productivity enhancement and economical option for field development in Saudi Arabian fields.[4] The objective of the study was to determine the efficiency of the APES in terms of permeability improvement as a synergic effect of polymer degradation by enzymes and calcium carbonate dissolution through acid generation.
Description of the Paper: The U-A reservoir unit is an eolian deposition where the primary facies are dune deposits. These sands are composed of quartz grains with feldspars. These grains are large in diameters and coated with illite clays, which made the formation sand friable. These sands require sand control and one of the techniques applied is to frac-pack the wells. The usual practice is to clean up the well as soon as possible to minimize formation damage. This process can take up to seven days, which results in frac fluid being left in the formation. This paper examines the effect of shut-in times following hydraulic fracturing treatments on the return permeability of the reservoir core. Lab studies included conducting coreflood experiments using reservoir cores and typical treatment fluids. The study was performed at bottomhole conditions (300°F) using cores with air permeabilities ranging from 25 mD to 28D. Polymer and breaker concentrations in the fracturing fluid were identical to those used in the field. Core plugs were tested by both methods: injecting and circulating the fracturing gel, and soaking it under pressure for up to seven days. Tests were performed in the absence and presence of a breaker, unencapsulated sodium bromate. Application: Guar gum and its derivatives are commonly used to prepare hydraulic fracturing fluids. During fracturing treatments, the polymer invades the formation and leaves a gel residue in the fracture and formation, which impairs well deliverability. Several factors like polymer loading, formation temperature, shut-in time and clean-up process contribute to the treatment outcome. A common belief (misconception) has been that long shut-in periods after fracturing a gas well will further reduce the permeability, and the impairment of delivery becomes severe. To avoid the resulting damage of the well, the treatment fluids are recovered while the rig on location, which costs rig time. This concept has led us to study the impact of shut-in time on the retained permeability of reservoir cores. Results, Observations, Conclusions: Experimental results reveal that 25% reduction in the permeability of reservoir cores occurs at a polymer loading of 45 lb/1,000 gals. A lower polymer loading of 35 lb/1000 gals caused less damage to the permeability. Most of the damage occurred during the first few hours of interaction of the gel with the core plug. Longer shut-in times did not cause additional damage. This study resulted in a significant cost savings by avoiding the need to flowback the well with the rig on location. Technical Contributions: Guar gum polymer used in hydraulic fracturing treatment can cause damage up to 25%. The damage occurred once the fracturing gel invades the formation. Longer shut-in times don't cause additional damage up to seven days. The degree of damage depends on the breaker concentration. Introduction Hydraulic fracturing technique is applied to create a conductive fracture in the pay zone to enhance well deliverability. A fracture is initiated by injecting a viscous fluid at a rate higher than the matrix can accept, based on Darcy's law. This will cause the formation to fracture in order to accommodate the high injection rates.1 The fracturing fluids are the most important components in hydraulic fracturing treatments. These fluids create fracture and transport the proppant, which in turn prevents the closure of the fracture after the treatment.2,3 Fracturing fluids should have sufficient viscosity to suspend and transport the proppant, should not damage the proppant pack or formation, should remain stable at reservoir pressure and temperature, exhibit low friction losses, having moderate efficiency, and should be resistant to shear degradation.3 After completion of the treatment, the gel must break down such that they can be removed from the formation. In a typical water-based fracturing fluid, high viscosity is generated by cross-linking polymer molecules (guar, HPG or CMHPG) with a multivalent cation like Ti(IV) and Zr(IV).4,5 In some cases, aluminum compounds are used for crosslinking.6 Cross-linking helps in achieving high viscosity necessary for fracturing without increasing polymer loading. Gels crosslinked with Ti and Zr ions have inherent problems of permeability reduction, fluid cleanup after treatment and damage to the proppant pack. This results in low fracture conductivity and poor well production.3
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