An impermeable mud cake layer, created on the formation face while drilling may be favorable for drilling operations but detrimental to well productivity. In vertical high pressure wells the layer is cleaned out while flowing back the well at adequate pressure drawdown. On the other hand, low pressure differential at the sand face in horizontal wells makes well cleanup treatments a necessity. Not all filter cake components are acid soluble. Commonly used inorganic acids and oxidizers are very reactive and cause uneven filter cake removal, which can affect the well's performance. As a result, there was a need to evaluate slow-reacting chemicals that can produce delayed uniform filter cake removal in horizontal wells. These treatment chemicals vary from the nonreactive acid-free microemulsion fluid systems to the weak organic acids, acid precursors, enzymes and chelating agents. The objective of this paper is to evaluate two chelating agent based treatments, NTA and EDTA, as filter cake removal treatments for a sandstone reservoir utilizing oil based mud (OBM) drill-in fluid (DIF) in Saudi Arabia. Coreflooding experiments were run under reservoir conditions to evaluate fluid-rock interaction. In addition, fluid-fluid compatibility was conducted between chelating agent and drill-in fluids base brines and between the chelating agent and formation fluid using high temperature, high pressure (HTHP) see-through cell. Solubility and static fluid-loss tests were conducted to evaluate the filter cake removal efficiency. Experimental results indicated that the NTA-based treatment was effective in removing up to 91% of the filter cake uniformly after soaking treatment for 24 hours. Fluid-fluid compatibility tests showed that the NTA-based chelating agent, when mixed with reservoir fluids, was free from precipitation or emulsion. On the contrary, mixing the chelating agent with the DIF carrier brine resulted in severe precipitation of insoluble permanently damaging byproducts. The laboratory study also observed that pH has a direct proportional relationship with the amount of precipitation. EDTA-based treatment results showed a removal efficiency of 93% after soaking treatment for 90 hours. Fluid-fluid compatibility tests showed that the EDTA-based treatment, when mixed with OBM DIF was free from precipitation or emulsion. On the contrary, mixing the chelating agent with the reservoir formation water resulted in severe precipitation of insoluble permanently damaging byproducts.

Well-control fluids were used during a routine overbalanced workover operation in an offshore well completed in high permeability sandstone. As expected, a fluid loss control pill was used to control the excessive losses encountered during this operation. However, due to the high permeability of the reservoir and the absence of sized particles in the pumped pill; large amount of fluids were lost to the formation before losses were controlled. The deep invasion of fluids laden with high concentration of polymer had inevitably resulted in severe formation damage and impaired production. Several attempts to clean out the wellbore and revive the well flow were unsuccessful with no injectivity either. The well was consequently suspended while a multidisciplinary team was formed to identify the cause of the impairment and recommend a treatment plan.A comprehensive review of detailed field operation and data related to the fluid losses accompanied with laboratory work to identify the damaging mechanism and formulate an optimized remedial treatment was conducted. The lab work included jar testing to assess compatibility and emulsion tendency when different wellbore fluids are mixed with each other and with formation fluids. Analysis of the samples collected from the wellbore was carried out and different treatment fluid options were evaluated using actual field samples. Core flood experiments were also conducted to assess the impact of high-viscosity pills on permeability and ability of remedial treatment in restoring the original permeability.Experimental results revealed partial removal of the polymer invading the core using organic acid. The designed pre-flush composed of mutual solvent with surfactant package was effective in breaking the emulsion from field samples and laboratory-prepared emulsions. A significant improvement in production from this well was realized by application of a cost effective formic acid-based chemical treatment. Proper treatment design with effective displacement technique were also attributed to the successful damage removal and regained well productivity.

Reactive mud cake breaker fluids in long open hole horizontal wells located across high permeability sandstone reservoirs has had limited success because they often induce massive fluid losses. The fluid losses are controlled with special pills, polymers and brine or water, causing well impairment that is difficult to remove when oil-based mud (OBM) drill-in fluids (DIFs) are used. This situation has resulted in the drive for an alternative cleanup fluid system that is focused on preventing excessive fluid leak off, maximizing the OBM displacement efficiency and allowing partial dispersion of the mud cake for ease of its removal during initial well production. The two-stage spacer application is composed of a nonreactive fluid system, which includes a viscous pill with nonionic surfactants, gel pill, completion brine and a solvent.Extensive laboratory evaluation was conducted at simulated reservoir conditions to evaluate the effectiveness of the OBM displacement fluid system. The study included dynamic high-pressure/high temperature (HP/HT) filter press tests and coreflood tests in addition to wettability alteration, interfacial tension and fluid compatibility tests.The spacer fluid parameters were optimized based on wellbore fluid hydraulic simulation and laboratory test results, which indicated minimal fluid leak off and a low risk of emulsion formation damage. Three well trials were conducted in a major offshore field sandstone reservoir drilled with OBM. All three trial wells (one single and two dual laterals), which were treated, have demonstrated improvement in production performance. This paper will discuss in detail the spacer fluids optimization process, laboratory work conducted and the successful field treatments performed.

Conventional lubricant products composed of different surfactant materials are required in water-based mud for drilling highly deviated and horizontal pay zone sections due to their lubricity associated with torque reduction and better penetration rate. Drill-in fluid (DIF) filtrate-induced formation damage in low-permeability gas reservoirs as a result of water blockage and reduced relative permeability to gas can be significant in view of the high capillary pressure associated with small pore throats. Formation damage risk assessment of the drilling lubricants utilization was therefore considered critical for a low-permeability gas reservoir development project. Lubricant product evaluation experiments were designed to provide the production impairment potential measurements using Berea and Unayzah sandstone cores with a laboratory formulated DIF and base brine containing 3-4% lubricant by volume and to confirm fluid compatibility with divalent salt (CaCl2) brine. Fluid compatibility and emulsion risk was investigated using mineral oil as the representative formation hydrocarbon fluid. Core flood and dynamic filtration tests were carried out at an estimated bottom-hole temperature of 250 °F and pressure of 1,000 psi for the high-temperature reservoirs while the compatibility tests were carried out at room temperature. Filter cake removal tests were also performed by using high pressure, high-temperature filter press equipment and synthetic disks to determine filter cake removal efficiency with acid brine breaker fluid. The obtained results from the laboratory study were integrated to evaluate and rank the lubricants based on their assessed formation damage risk. The test results showed that both lubricant return permeability and compatibility tests were important in selecting the best performance lubricant. This paper discusses the experimental analysis of the formation damage potential of 12 commercially available water-based mud (WBM) lubricants. It also provides an insight into the formation damage (FD) impact of the drilling fluid lubricants on gas reservoir deliverability.

Injection water-induced formation damage evaluation is considered critical in a low-permeability (2 md) oil reservoir development because of the potential bridging of narrow pore throats by in-situ scale precipitates. This problem can be mitigated with processed low-salinity water, albeit at significantly high capital expenditure associated with water processing facility that could erode the economic margin of the project. Laboratory fluid compatibility tests and software simulation were therefore conducted to appraise the risk of inorganic scale deposition during water injection in an undeveloped carbonate reservoir with high-salinity formation brine (TDS ~205 g/L). The laboratory experiments were initially carried out with both synthetic and actual field samples including formation water extracted from pressurized downhole fluid tester. Coreflood and fluid-fluid compatibility tests were carried out at estimated bottom-hole temperature of 150 °F and pressure of 1,000 psi. Comprehensive mixed-brine simulation software was also used to determine the inorganic scaling tendency expected with the use of seawater, produced water and diluted produced water for the planned injectors. The study identified an inherently high calcium sulfate risk associated with the planned seawater injection in the new reservoir while the highest combined inorganic scale precipitation was observed at approximately 1:1 ratio for the formation brine-seawater mixture. This paper discusses the laboratory fluid compatibility experiments and scale prediction analysis for different injection water utilization while providing an insight into the potential impact of scale risks associated with seawater injection in an onshore development reservoir with high divalent-salt content formation brine.