Barite sagging is one of the common issues while drilling high pressure-high temperature wells. This will cause variation in the mud weight in both vertical and deviated wells. Barite sagging can cause many problems such as; density variations, well-control problems, stuck pipe, downhole mud losses, and induced wellbore instability. The objective of this study is to assess the effect of adding a new copolymer to the invert emulsion drilling fluid to prevent the sagging issue. Sag test was conducted under static conditions over a wide range of temperature (200°F to 350°F). Sag test was performed using vertical and decline (45° degree) aging cell. In addition, the effect of adding the new copolymer on the rheological properties and the electrical stability of the invert emulsion drilling fluid was evaluated. The results obtained showed that adding 1 lbm/bbl of the new copolymer had no effect on drilling fluid density (14.5 ppg). The new copolymer slightly enhanced the electrical stability of the invert emulsion drilling mud. The new copolymer had a minor effect on the plastic viscosity, yield point, and gel strength. Adding 1 lbm/bbl of the copolymer prevent barite sagging at 350°F, where the sag factor was 0.55 before adding copolymer, and 0.503 after adding it. The storage modulus (G′) was increased by 40% after adding 1 lbm/bbl of the new copolymer confirming the sag test results. There was no effect of adding the new copolymer in the filtration loss and filter cake thickness. The novelty of this work is the development of a new drilling fluid formulation that can be used in drilling HPHT wells without any sag issue. This development will help the drilling engineers to safely drill deep wells and maintain the drilling fluid integrity during the drilling operation. In general, this will reduce the overall cost of the drilling operation by reducing the non-productive time in solving many issues such as well control, loss of circulation, or pipe sticking.
Summary Matrix acidizing of high-temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high-chrome-content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid-diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper, we evaluate the results of the first field application of this chelating agent to acidize a sour, high-temperature, tight gas well completed with high-chrome-content tubulars. Extensive laboratory studies were conducted before the treatment, including corrosion tests, coreflood experiments, compatibility tests with reservoir fluids, and reaction-rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water-wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flowback fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flowback samples. The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where hydrochloric acid (HCl) or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flowback samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer-term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
Seawater is injected to maintain the reservoir pressure that supports the oil production from carbonate and sandstone reservoirs. In certain regions, the seawater contains more than 4,000 ppm sulfate, and the formation contains more than 19,000 ppm calcium; this will cause calcium sulfate precipitation at the reservoir conditions. The precipitate at the reservoir conditions will be anhydrite, and it will cause formation damage that will reduce the well injectivity. Stimulation treatments are required to recover the well injectivity; this requires stopping water injection to perform the stimulation treatments, and also it requires flowing back the well after stimulation treatment.In this study, we are proposing a new method that we can use to stimulate water injectors without stopping the water injection. The new method includes adding a chelating agent to the injected seawater at the wellhead at 15 wt% concentration. The fluid will be injected at the surface with the seawater with a specific dose to achieve the required concentration. Several solubility and coreflooding tests were performed with actual carbonate cores and GLDA (glutamic-di acetic acid) chelating agent at different temperatures. The chemical injection does not need coiled tubing and can be injected at the surface with the seawater. The chelating agents will sequester all calcium in solution and will prevent the calcium sulfate precipitation. GLDA chelating agent will be used with seawater, with no need to use treated or fresh water. Also, flowing back the well is not required because the fate of GLDA in the aquifer is soluble.Solubility tests up to 250 F at high pressure showed that the GLDA is stable with seawater. Coreflood experiments and computed-tomography scans showed the ability of GLDA in the creation of dominant wormholes through 6-and 1.5-in. carbonate cores at 212 and 150 F, respectively. GLDA chelating agent can be used to stimulate seawater injectors without additives because this chemical is stable and mild with the well tubulars. Previous corrosion studies on GLDA showed that its corrosion rate is in the allowable range without adding corrosion inhibitors.
Summary Acidizing sandstone formations is a real challenge for the oil and gas industry. Fines migration, sand production, and additional damages caused by precipitation are some of the common concerns related to sandstone treatments. Furthermore, the complexities of sandstone formations require a mixture of acids and loadings of several additives. The environmentally friendly chelating agent glutamic acid N,N-diacetic acid (GLDA) was used successfully to stimulate deep gas wells in carbonate reservoirs. It was tested extensively in the laboratory to stimulate sandstone cores with various mineralogies. Significant permeability improvements were reported in previous papers over a wide range of conditions. In this paper, the result of the first field application is evaluated with a fluid based on this chelating agent to acidize an offshore, sour oil well in a sandstone reservoir. The field treatment included pumping a preflush of xylene to remove oil residues and any possible asphaltene deposited in the wellbore region, followed by the main stage that contained 25 wt% GLDA, a corrosion inhibitor, and a water-wetting surfactant. The treatment fluids were displaced into the formation by pumping diesel. The treatment fluids were allowed to soak for 6 hours, then the well was put into production, and samples of flowback fluids were collected. The concentrations of key cations were determined using inductively coupled plasma, and the chelant concentration was measured using a titration method with ferric chloride solutions. Corrosion tests conducted on low-carbon-steel tubulars indicated that this chelant has low corrosion rates under bottomhole conditions. No corrosion-inhibitor intensifier was needed. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without causing sand production, or fines migration. Analysis of flowback samples confirmed the ability of the chelating-agent solution to dissolve various types of carbonates, oxides, and sulphides, while keeping the dissolved species in solution without causing unwanted precipitation. Unlike previous treatments conducted on this well, where 15 wt% hydrochloric acid (HCl) or 13.5 wt%/1.5 wt% HCl/hydrofluoric acid (HF) acids were used, the concentrations of iron and manganese in the flowback samples were negligible, confirming the low corrosion rates of well tubulars when using GLDA solutions.
Matrix stimulation is commonly utilized to increase well productivity and it is a process in which fluid selection plays a key role in treatment success. However, in offshore fields, the acid formulation must not only be effective in damage removal but it also has to meet stricter HSE regulations while safeguarding expensive and complex installations from corrosion impact. In high temperature environments or where sensitive metallurgy is deployed, higher doses of corrosion inhibitors are required as well as additional additives in order to avoid unwanted reactions, further complicating the handling and HSE aspects of such acids. The environmentally friendly chelate, glutamic acid N,N-diacetic acid GLDA, has been examined as an alternative for acidizing and descaling treatments, demonstrating good field performance in terms of productivity and injectivity increase. All this achieved while providing a safe and convenient system for handling, due its low toxicity, fewer required additives and biodegradability. Numerous laboratory tests have measured and confirmed considerably less corrosion risk, across a wide range of conditions, when compared to conventional formulations based on both HCl and organic acids. Within this paper, the field performance of the GLDA system will be evaluated under even more challenging conditions, endured during the acidizing of an offshore well in the North Sea. The wellwork programme for the low rate gas producer consisted of performing two new perforation runs, followed by the injection of the GLDA treatment, which was then bullheaded into the formation with a nitrogen assist. The treatment formulation consisted of GLDA diluted in fresh water with trace amounts of surfactant and mutual solvent to aid in the flow-back of the spent acid. Due to an unexpected power failure on the platform, the treatment remained stagnant in the tubing for some 28 hrs at 300°F. As this was the first GLDA treatment in this field, this situation appropriately raised potential well integrity concerns; as would most certainly have been the case with a conventional HCl acid package. However, once the operation was restarted the acid was successfully bullheaded into the formation and no issues resulted with the low carbon and CRA based metallurgy of the completion even after this extensive unplanned exposure. Additionally the treatment resulted in a significant productivity increase. These operations and results demonstrated not only the gentle nature of GLDA for integrity considerations; but also an effective cleanout of perforations and near wellbore area as required from a replacement system. The success of the treatment proved the intrinsic value and reduced risk that can be accessed by use of such systems.
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