Brine-based reservoir drilling fluids are a special class of fluids designed to minimize formation damage, provide the necessary hole cleaning, help reduce wellbore cleanup time and cost, and allow reservoirs to be produced to the maximum of their potential. These fluids should address the wide range of difficulties frequently encountered in horizontal drilling, completion, and workover operations. Filtration control chemicals for currently available drill-in fluid systems exposed to extremely high bottomhole temperatures and pressure conditions are not effective or stable for drilling long horizontal sections of the reservoir. Failure to secure a low filtration rate and thin wallcake causes stuck pipe and loss of expensive downhole tools.Conventional fluid loss control additives for high performance brine-based drill-in fluids include nonionic water soluble polymers, such as starches, derivatized starches, gums, derivatized gums, and cellulosics. Cross-linked starches are often considered the benchmark of performance for utilization in reservoir fluids, but they do not have the thermal stability required for successful deployment at temperatures exceeding 300°F for extended contact periods.Conventional linear synthetic polymers are also utilized, but oftentimes they require another additive, such as phyllosilicate particles, to be able to effectively function as fluid loss control additives. The use of clay can be problematic in drill-in fluids, as removing the clay from the formation can be difficult because it infiltrates into pores. Furthermore, the addition of the linear synthetic polymers dramatically increases the viscosity of the fluid, which can result in increased equivalent circulating densities (ECD) and decreased drilling rates.Through advanced synthetic polymer techniques, a novel polymeric fluid loss control additive has been developed for brine-based reservoir drill-in and completion fluids. The new polymer provides enhanced thermal stability to temperature in excess of 400°F in monovalent and divalent halide brines. This paper presents detailed fluid formulations and discusses the polymer evaluation data under simulated downhole HPHT conditions.

Excessive unsupported casing growth at the surface is a problem which could dramatically affect the integrity of the steam injection wells. This problem was recently encountered in a Middle East oil field where severe cement fallback on numerous wells caused excessive casing growth upon injecting steam. Surface steam supply lines could accommodate up to 4 ft (1.2 meters) of casing growth, but the wells with poor cement bond experienced up to 8 ft of wellhead movement. Remedial cement placement was not an acceptable option for injection wells that require perforated casing. An alternative economical method to control casing growth was therefore needed. Fresh water was normally placed in the annulus, which evaporated and released to the atmosphere due to the very high steam temperature (ca. 575°F/300°C). Heat transfer to the casing was very high, causing the excessive casing expansion. Controlling this heat transfer will limit wellhead movement while retaining the energy in the steam for more efficient reservoir heating and oil recovery. A high temperature insulating fluid was custom-designed for these subject wells. The solids-free water-based fluid had low inherent heat transfer and was gelled with a unique stable inorganic viscosifier to prevent convection at the target temperature. Preventing convection is a key factor in reducing heat transfer. After four days of steam injection, the operator reported that wellhead movement was half of that in offset wells completed with fresh water as the packer fluid. This paper will present and discuss the lab and field data for the new insulating fluid which offers several advantages in reliability and performance for extreme temperature applications such as the geothermal and steam injection wells.

While drilling underbalanced with potassium chloride (KCl) brine and injected nitrogen generated by a membrane filter, black precipitate and heavy scale deposits on the drillstring were observed. The brine was treated with phosphate ester and an amine-based inhibitor at the optimum pH range to mitigate corrosion. A robust onsite monitoring program of the fluids' properties and the inhibitor concentration was carried out to help ensure proper control of corrosion during the underbalanced drilling (UBD) operations Analysis of scale-like deposits scraped off the drillstring was predominantly magnetite with trace amounts of siderite and KCl. Little to no scale was seen on the drillstring below the nitrogen injection point indicating that the injected gasses seemed to be a contributor to the issue.Examination of the drillstring surfaces beneath these scales and API corrosion rings did not exhibit metal loss or pitting indicating these scales were not consistent with corrosion. Further, scale formation continued to be observed as drilling continued under nil oxygen conditions when cryogenic nitrogen was employed and oxygen levels of less than 1% were maintained. Laboratory and field engineers were deployed to collect samples of the brine used for drilling, the scale deposits, solids recovered at the shale shaker screens, and the fluid returns from the wellbore. The precipitate was mostly amorphous iron oxide with magnetite (i.e., combination of Fe (II) and Fe (III) oxides that is ferrimagnetic in nature). This paper will present the field and lab data generated which helped in discovering the root cause of the problem and developing practical solutions. IntroductionField and laboratory investigation was undertaken to find the root cause of scaling of conventional drill pipe during UBD using a 2% KCl brine. Nitrogen generated by membrane filter was initially utilized to establish underbalanced conditions allowing influx from the drilled formation (i.e., hydrocarbons and water). Build up of a black precipitate or scale was observed on the outside of the pipe during a trip out of the hole. At first, corrosion was suspected and steps were taken to minimize the effects of corrosion. Cryonitrogen and oxygen scavengers were applied along with the corrosion inhibitors, but this treatment did not stop the precipitate formation. Underbalanced drilling specialists and laboratory scientists were sent to observe and analyze the situation on-sight and help determine the underlying cause of the precipitation phenomena and its source (i.e., scaling or corrosion).In order to fully recognize the concepts presented in this paper and provide the appropriate details, a brief overview of corrosion and its causes is provided. Corrosion of metals is a worldwide problem faced by the petroleum industry that also impacts many other facets of everyday living. The effects of corrosion costs billions of dollars in repairs each year not counting the costs of corrosion prevention (Muzyczko 1978). Developing a solution for such a large scale issue req...

The use of high density "mud cap" tripping pills to provide adequate hydrostatic pressure downhole for well control is a common practice on managed pressure and underbalanced drilling operations. However, placing a high density tripping fluid on top of a lower density drilling fluid is an attempt to defy gravity, and too often the result is large volumes of the two fluids comingling, ruining the potential reuse of both. Viscosifying the tripping pill itself has been tried with some success, but problems encountered have included more difficult movement and storage of the tripping fluid, along with the risk of increasing the well’s bottomhole pressure while pumping the large, viscous pill into place. A better solution to the comingling issue is to place a physical barrier between the two fluids to prevent their mixing. A novel fluid with robust thixotropic properties was developed to serve this barrier fluid function. The shear thinning properties of this fluid allow for ease of placement in the wellbore prior to tripping, and when the high density "mud cap" is displaced on top of the barrier fluid the comingling of the tripping fluid and the drilling fluid is prevented. After tripping the drillstring back to the top of the barrier pill, the pill can be washed through and disposed of at surface, leaving a clean drilling fluid in the wellbore. The development and initial use of this barrier fluid are the subjects of this paper.

Managed pressure drilling operations pose several challenges to the upstream oil industry. While tripping the drillstring, the bottomhole pressure of the wellbore must be maintained at the nominal formation pressure, and the solutions currently used have less than optimal success rates in high angle wellbores. A balanced mud cap displaced into the well before a trip can supply the bottomhole pressure required, but the cap is prone to fall through the lighter drilling fluid below. Viscosifying the mud cap is seldom successful, and placing a high viscosity spacer between the two fluids has not been a reliable solution, until now. The spacer chemistry presented in this paper successfully addresses those limitations. This barrier spacer meets the operational tripping requirements because it is easy to pump and spot, and robust enough to hold the heavy mud cap above the drilling fluid, yet easy to remove when it is no longer required. Since its introduction, some minor shortcomings of the spacer were identified, and a modified formulation has been developed to improve the mixing and deployment of the spacer.