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This paper describes the composition and properties of a completion and workover fluid that can be weighted to 18.0 lb/gal (2157 kg/m) with an acid-soluble weighting agent. Several field case histories where these fluids were used in high-density gravel-packing operations are described. Property measurements demonstrate the stability, and highly pumpable flow characteristics of the weighted pumpable flow characteristics of the weighted fluids. Introduction Clear, solids-free brines have been used extensively in completion and workover operations, and, where applicable, these have proven quite effective. There are several reasons, however, why a solids-free brine may not meet the requirements of a particular completion or remedial operation. It then is necessary to add solids to improve or to impart certain properties to the fluids - i.e., improved hole cleaning. Rig hydraulics may be inadequate to clean cuttings or sand satisfactorily from the well using the brine alone; therefore, it is necessary to add a viscosifier to increase the brine's lifting capacity. At other times, the addition of bridging materials may be required to control loss of brine to the formation. Excessive loss of brine to the formation may result in formation damage, failure to maintain sufficient hydrostatic head, or unacceptable brine costs.Another reason for adding solids to a clear brine is to increase fluid density to control formation pressures. However, this is not widely practiced. Saturated sodium chloride provides a fluid density of 10.0 lb/gal (1198 kg/m) and calcium chloride brines are usable up to 11. 7 lb/gal (1402 kg/m) at ambient temperatures above 60 deg. F (15.6 deg. C). In the past few years, calcium bromide brines with densities up to 15.0 lb/gal (1797 kg/m3) have been used, but because of the high cost of this brine, its use cannot always be justified. Because of these limitations of the clear brines, other means would be needed to meet the higher density requirements of completion and workover. This paper describes the requirements, composition, and properties of a solids-laden brine system that has proven successful in field application. Requirements of a Solids-Laden Brine Solids-laden fluids often are considered undesirable as completion and workover fluids because these fluids could transport particles into the formation, resulting in particle plugging. This effect has been shown to exist by particle plugging. This effect has been shown to exist by several investigators and is a source of formation damage. However, several design criteria can be used to prevent, or at least minimize, particle invasion. prevent, or at least minimize, particle invasion. One design consideration is to form a particle bridge at the sand face as quickly and effectively as possible. This can be done by selecting the particle-size distribution and concentration of solids for the workover or completion fluid. Abrams concluded that to minimize particle invasion, the bridging materials should be equal to or greater than one-third the median pore size of the formation and should be present in quantities of at least 5% vol of the solids.Ultrafine particles are more apt to be transported into the formation as discrete particles, such as would occur in a deflocculated state. For this reason, a flocculating environment is desirable since the fines tend to exist as aggregates and are more likely to be retained by the bridging particles. Salt brines are, of course, highly flocculating to particles. Salt brines are, of course, highly flocculating to dispersed solids and are, therefore, highly desirable as the water phase. JPT P. 35
Abstract Acid Fracturing has been one of the most effective stimulation technique applied in the carbonate formations to enhance oil and gas production. The traditional approach to stimulate the carbonate reservoir has been to pump crosslinked gel and acid blends such as plain 28% HCL, emulsified acid (EA) and in-situ gelled acid at fracture rates in order to maximize stimulated reservoir volume with desired conductivity. With the common challenges encountered in fracturing carbonate formations, including high leak-off and fast acid reaction rates, the conventional practice of acid fracturing involves complex pumping schemes of pad, acid and viscous diverter fluid cycles to achieve fracture length and conductivity targets. A new generation of Acid-Based Crosslinked (ABC) fluid system has been deployed to stimulate high temperature carbonate formations in three separate field trials aiming to provide rock-breaking viscosity, acid retardation and effective leak-off control. The ABC fluid system has been progressively introduced, initially starting as diverter / leak off control cycles of pad and acid stages. Later it was used as main acid-based fluid system for enhancing live acid penetration, diverting and reducing leakoff as well as keeping the rock open during hydraulic fracturing operation. Unlike in-situ crosslinked acid based system that uses acid reaction by products to start crosslinking process, the ABC fluid system uses a unique crosslinker/breaker combination independent of acid reaction. The system is prepared with 20% hydrochloric acid and an acrylamide polymer along with zirconium metal for delayed crosslinking in unspent acid. The ABC fluid system is aimed to reduced three fluid requirements to one by eliminating the need for an intricate pumping schedule that otherwise would include: a non-acid fracturing pad stage to breakdown the formation and generate the targeted fracture geometry; a retarded emulsified acid system to achieve deep penetrating, differently etched fractures, and a self-diverting agent to minimize fluid leak-off. This paper describes all efforts behind the introduction of this novel Acid-Based Crossliked fluid system in different field trials. Details of the fluid design optimization are included to illustrate how a single system can replace the need for multiple fluids. The ABC fluid was formulated to meet challenging bottom-hole formation conditions that resulted in encouraging post treatment well performance.
- Asia > Middle East (0.68)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Selective Multi-Stage Stimulation in Open-Hole Completion in a Carbonate Formation Using Dynamic Diversion: Case History in UAE
Leguizamon, Javier (Halliburton) | Jaiyeola, Abiodun Isiaka (ADNOC) | Al Shehhi, Hessa Ali Mohammed (ADNOC) | Talib, Noor Nazri (ADNOC) | Ottolina, Renny (Halliburton) | Rogers, Bryan (Halliburton) | Dunlop, Tyson (Halliburton) | Nechakh, Abderaouf (Halliburton)
Abstract Achieving successful stimulation with optimum production performance in open hole horizontal completions is complex in carbonate reservoirs. When stimulation becomes necessary in openhole completions, methods to perform multistage fracturing with proper isolation, are limited. Effective application of dynamic diversion provides a fit for purpose solution to this challenge, allowing to selectively place fracturing treatments, reaching the productivity enhancement targets. Prior to applying this technique a series of formation testing needs were conducted, including step rate test and leak off test. Outputs of the tests help optimize pumping schedule and strength of the acid mixture. The method involves dynamic isolation while performing dual injection of acid through Coiled Tubing (CT) and water-based fluid through annulus. A precise fracture initiation is established through the stagnation pressure developed when the CT fluid is jetted at high velocity. The pressure generated act as barrier replacing mechanical isolation (Surjaatmadja 1998, Surjaatmadja et al. 1998). Dynamic diversion is achieved with a specially designed downhole Hydrajetting tool, which generates a specific pressure drop across its nozzles. Down-hole acid mixing is highly influenced by leak off rate along the open-hole section, as well as the maximum allowable rates through CT and Annulus; this is particularly critical for surface preparation of the fracturing acid. Treatment acid is pumped through the CT at highest possible pumping rate within the pressure limitation of the CT. Fresh water based fluid is pumped in the annulus at 80% of the fracture gradient. Reservoir stimulation with this technique allowed completing 20 treatments in less than 18 hours, proving its remarkably efficiency. With proper depth correlation, the project targeted the sweet spots as initially designed based on petro-physical and geomechanical properties of the reservoir along with the presence of natural fractures network. Post-treatment rates observed during the initial production suggested the method is effective for acid fracturing of carbonate reservoirs with gas-condensate. Post-fracture simulations involving treating pressures matching and initial production analysis, support these observations. Recommendations are focused on technologies to perform additional measurements confirming fractures geometry achieved and contribution to production. Beyond isolation, the petrophysics and geomechanics of the zone of interest as well as the surrounding formations represented additional challenges. Leak off along the horizontal and depleted adjacent layers required an accurately engineered pump schedule. Several combinations of rates, volumes and fluid types had to be simulated to obtain the optimum design. The paper summarizes the design processes, selection criteria, challenges, and lessons learned during the planning & execution phases. It will also pave the way for future development of tight carbonate reservoirs which are available in company's portfolio currently undeveloped due to insignificant well productivity with important in place volume.
Abstract Generally carbonate acidizing job is carried out using HCl based stimulation fluids because of its effectiveness to dissolve and/or to disperse materials obstructing flow. But this effectiveness also creates a major drawback of its use; that is only surface dissolution and low penetration due to fast rate of reaction with carbonates. One method to overcome this problem is to mix appropriate organic acid with HCl but the reactions between organic acids and carbonates is less understood than those of HCl with carbonate rocks because of the presence of CO2 and the precipitated reaction products; the organic salts of calcium and magnesium. Therefore much testing is needed to know the right organic acid to be mixed with HCl for a particular reservoir. Also they normally do not react to their full acid strength because of the release of CO2 from carbonate dissolution and the cost of organic acid is significantly higher than that of HCl for equivalent mass of rock dissolved. In this paper we propose a new method to overcome these tribulations. In this method, Nickel nanoparticles mixed with water are injected into the formation before injecting stimulating fluid. Afterwards when the HCl based stimulating fluid is injected into the formation, it reacts with the Carbonates and produce CO2. As sson as CO2 is formed, Nickel Nanoparticles converts gaseous CO2 into carbonic acid (aqueous CO2). What nickel nanoparticles do is that it accelerates the natural conversion of CO2 to carbonic acid. Use of nanoparticles reduces the amount of CO2 by converting it into Carbonic acid (enhancing the stimulation job), reducing the cost and facilitating the reaction between organic acid and carbonate rocks. Introduction Carbonate reservoirs present tremendous completion, stimulation and production challenges because they are vertically and laterally heterogeneous, with natural permeability barriers, natural fractures and a vast array of porosity types, from intercrystalline to massive vugular and cavernous porosity. Consequently it is very difficult to target the injection of stimulation fluids to a particular zone of interest. This leads to inefficient use of stimulation fluids. So there is a need for the development of new stimulation technique which would result in more efficient use of stimulation fluids and remove the drilling damage at a reasonable cost. While permeability is a major factor in the distribution of acid along a completion for many reservoirs, pre-stimulation skin damage, intermixed rock types with different acid-rock worm holing characteristics, distance between zones, and differential reservoir depletion also play important roles in the effective stimulation of the reservoirs Oil and gas companies are developing carbonate reservoirs of deeper and deeper depths in order to meet the demand of increasing worldwide energy consumption. Hydrochloric acid is the most commonly used acid for carbonate acidizing due to its low cost and high dissolving power but enhancing productivity from these reservoirs poses a challenge in stimulation fluids due to the increase in bottom hole temperature. The rapid reaction rate between HCl and carbonate limits the penetration of HCl into the formation, especially at low pumping rates. The reaction of HCl often needs to be retarded by gelling, emulsifying, or adding viscoelastic surfactants. In addition to the high reaction rate, HCl is very corrosive to well tubulars. Expensive corrosion inhibitors can protect the tubulars at high temperatures only for a short period of time. Other problems have been shown in Fig. 1–4.
Abstract Excessive water production from unwanted zones in oil producing wells is one of the major challenges faced by the oil industry. The applicability of organically crosslinked polymer (OCP) systems as sealants for water shutoff treatments in temperatures up to 350°F is well documented. However, their effectiveness at temperatures above 350°F has not been evaluated. This paper presents experimental data from using an OCP system for water shutoff treatments at 400°F. At temperatures around 400°F, crosslinking is expected to happen faster and can lead to premature gelation of the recipe before the entire treatment is in place. Thus, controlling the gelation time at such temperatures is extremely crucial. Optimizing the amount of retarder is essential to provide adequate time for placement of the treatment fluid. This paper provides gelation time data at temperatures between 350 and 400°F with different amounts of retarder. With an optimum amount of retarder, the OCP showed a gelation time of 1 hr 20 min. This paper also describes the experimental setup used to study and determine the long-term stability of the OCP system at 400°F. Sand packs measuring 1-ft long were used for the test to simulate formation conditions. Once the optimized OCP recipe was gelled inside the sand pack, measurements were taken by gradually applying incremental differential pressure (ΔP) to evaluate the sealant at temperature, as well as the threshold ΔP the system could withstand. Even after one month at 400°F, the OCP recipe was able to sustain a AP of 950 psi over the sand pack. The data indicates the applicability of this system as an effective conformance product to shut off water-producing zones over an extended period of time at 400°F.
- North America > United States (0.70)
- Asia (0.69)