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Abstract Gravel packing, being one of the most reliable and robust downhole sand control techniques, is often the preferred method for establishing sand control. In reservoirs where the pressure has fallen below the water gradient, gravel placement using water based fluid will produce a high overbalance leading to excessive losses of fluid that might deeply invade the formation, cause premature bridging, and fracture the formation. The main focus of this paper is to identify fluids and techniques for gravel packing a depleted reservoir and evaluate the best technique and a fluids package for a candidate well. A well candidate in the Mediterranean is planned to be completed with cased hole gravel pack and it is a twin of a cased and perforated gas well that started producing formation sand after 4 years of production. Continued production from the reservoir is expected to drive down the pressure to 7.5ppg by the time, when candidate well is completed. Several techniques for gravel packing a depleted reservoir have been considered which included diesel, alcohol-, oil-, gas- and water-based fluids. However after extensive lab testing the most suitable fluids package for the well was found to be conventional water packing. Contrary to expectation, formation damage tests indicated that water based gravel packing caused less damage than non-viscous oil based fluids for this particular candidate well. Solids-free high-temperature perforation kill pill and breaker package were also designed for the well to be stable for up to 4 days, which pushed the limits of solids free kill pills currently available in the industry. The paper will discuss in detail the gravel packing fluid package selection methodology, and completion fluid, gravel pack fluid, kill pill and breaker fluids package design and evaluation for the candidate well.
- Asia (0.93)
- North America > United States > Texas (0.68)
- North America > United States > Alaska > North Slope Borough (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Mineral (0.46)
- 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)
- (23 more...)
Selective Stimulation and Water Control in High-Water-Cut Wells: Case Histories from Upper Magdalena Valley Basin in Colombia
Rodriguez, E.. (Ecopetrol) | Duarte, C.. (Ecopetrol) | Martinez, W.. (Ecopetrol) | León, J.. (Ecopetrol) | Ortega, A.. (Schlumberger) | Lastre, M.. (Schlumberger) | Milne, A.. (Schlumberger) | Navarro, C.. (Schlumberger)
Abstract A brownfield located in the southwest region of Colombia, in the Upper Magdalena Valley Basin, produces from shallow marine sandstones of the Upper Cretaceous-aged Monserrate Formation. Net pay varies from 50 to 150 ft, with porosity between 17 and 22%, and permeability of 80 to 360 mD. The wells in this field, which has been under water injection since 1997, produce with a high water-cut, which in most cases exceeds 90%. Water injection has led to inorganic scale, organic scale, asphaltene deposition, fines migration, and the need to treat the wells using hydraulic fracturing and/or matrix acidizing techniques. Conventional matrix stimulation treatments require the use of straddle packers to ensure complete zonal coverage and frequently result in increased water production with no significant increase in oil production, making the treatments uneconomical. To reduce the cost of and increase the success rate of matrix treatments, a Combined Diverter and Conformance Control (CDCC) fluid was introduced. This allowed the stimulation to be performed when mechanical diversion was not possible due to wellbore restrictions. The CDCC fluid is pumped in alternating stages with the acid system to divert the treating fluid and provide water conformance control. A recent stimulation campaign, using the CDCC fluid in this field, resulted in a 30% increase in oil production while reducing the water cut by 10%. The average cost of the treatments was reduced by 27%, when compared to conventional treatments. This has led to a reassessment of the economics of the field, with the possibility of recovering an additional ~3% of the reserves in place. The plan is to treat routinely underperforming wells, irrespective of the water cut. The ability to increase economically the oil production in this marginal field has led to a reassessment of other similar fields approaching their economic limit.
- South America > Colombia > Huila Department (0.84)
- South America > Colombia > Tolima Department (0.60)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.66)
- Geology > Mineral > Silicate > Phyllosilicate (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- South America > Colombia > Tolima Department > Upper Magdalena Basin (0.99)
- South America > Colombia > Huila Department > Upper Magdalena Basin (0.99)
- South America > Colombia > Huila Department > Magdalena Basin > Tello Field (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 6 > Dulang Field (0.99)
Abstract Fracturing treatments in tight-gas sands often suffer disappointing production results. Conductivity damage caused by immobile gel filtercakes is often cited as a probable damage mechanism. Breaker requirements for reducing the viscosity of filtercakes remain a challenge, particularly at suspected filtercake concentrations of greater than 600 lbm/1,000 gal. Previous studies measured the rheology of non-crosslinked hydroxypropyl guar (HPG) across broad ranges of molecular weight (MW), temperature, concentration, and shear rate. The reported rheology model provided a means to experimentally evaluate breaker requirements to achieve a target uncrosslinked filtercake viscosity. Experiments were conducted to determine kinetics of polymer degradation by simple hydrolysis at temperature and degradation by sodium chlorite and sodium persulfate breakers. Temperatures ranged from 85 to 280°F, while breaker concentrations ranged from 0 to 80 lbm/1,000 gal. HPG concentration was held at 1 lbm/gal of 260 kg/mole HPG. The viscosity profiles during the experiments were matched with the rheology model to infer MW decline profiles and thereby determine the rate laws for reaction with the polymer. It was found that efficiencies of breakers on breaking backbone linkages of HPG were only 2 to 5%, with the remaining breaker consumption apparently not reducing the molecular weight of the polymer. The rate laws for the breakers were found to be first order in breaker and first order in linkage concentration. The rate laws were used to make projections on the amount of breaker required to reduce concentrated gels to an arbitrary target viscosity.
Abstract In the Llanos basin of Colombia, there are shallow, highly permeable, poorly consolidated sandstone reservoirs close to oil-water contacts. The Carbonera formation is typical—several small, highly permeable (600 to 3000 mD) producing sands, with poorly defined barriers. High production rates and low bottom hole flowing pressures (BHFP) result in water coning and sand production. One solution is a stacked frac-pack completion. In these applications, conventional cross-linked fracturing fluids have limitations. High polymer concentrations and viscosity are required to control fluid leak-off and create a sufficiently wide hydraulic fracture to admit proppant. High fluid viscosity has led to uncontrolled fracture growth into oil-water contacts, while the high polymer concentration decreases fracture conductivity and effective half-length. A linear fluid comprised of polyacrylamide and polysaccharide polymers has proved an effective solution. The polyacrylamide greatly enhances fluid efficiency and elasticity, while reducing friction pressures and horsepower requirements. Fluid elasticity ensures adequate proppant transport. Fluid efficiency is determined by the polyacrylamide concentration and adjusted to achieve the required fracture geometry. The use of this fluid along with a geomechanical model and pseudo 3D fracturing simulator ensures that the propped fracture remains within the producing sand, with increased effective fracture half-length and conductivity. The polyacrylamide reduces the effective permeability to water and limits potential conning, when the well is produced. Wells completed with frac-packs using the linear fluid produce an average of 1420 bbl/day of fluid with 20% water-cut. The fluid efficiency during the treatments varies between 30% and 15% as a function of permeability. Offset conventionally gravel packed wells with a lower bottom hole flowing pressure (BHFP) average 980 bbl/day of fluid with 60% water-cut. Frac-packs, using an efficient linear fluid together with a geomechanical model and a pseudo 3D fracturing simulator have greatly improved the economics of producing these highly permeable reservoirs—maximizing production and recoverable reserves, while minimizing water production.
- North America > United States > Louisiana (0.47)
- South America > Colombia > Meta Department (0.34)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- South America > Colombia > Meta Department > Llanos Basin > Cano Sur Block > Carbonera Formation (0.99)
- South America > Colombia > Llanos Basin (0.99)
- North America > United States > Louisiana > Hackberry Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > P474 > Darcy Formation (0.99)
Successful Application of a New Solids-Free Fluid Loss System in Acid Fracturing Treatments Achieved Significant Well Productivity Improvements in Saudi Arabian High Condensate Gas Producers
Leal, Jairo (Saudi Aramco) | Solares, J. Ricardo (Saudi Aramco) | Taq, Ali (Saudi Aramco) | Duarte, Jorge (Saudi Aramco) | Al-Shammari, Nayef (Saudi Aramco) | Al-Ruwaished, Azmi (Saudi Aramco) | Eoff, Larry (Halliburton) | Izquierdo, Guillermo (Halliburton)
Abstract Controlling fluid matrix leakoff into the formation is of critical importance during fracture stimulation treatments to ensure objectives are met. Decreasing the amount of fluid leakoff increases the volume that is available to maintain and propagate a hydraulic fracture. The need to minimize fluid leakoff is even more significant during acid fracturing since maintaining the fracture is difficult because of the ability of acid to spend quickly as it enters the formation. Traditional approaches utilize solids-laden viscous gels to reduce the volume of fluid leakoff as a fracture is propagated; however, it has been amply documented that the solids typically used are capable of damaging the formation if not properly removed after the treatment. Moreover, removal of treatment gels, which is required to minimize formation damage, is contingent on selection and design of breakers or other compounds, which are often chosen based on a number of uncertain reservoir parameters. This paper will present both laboratory and field application results from a new solids-free fluid loss (SFFL) system designed to reduce matrix permeability to aqueous fluids, thereby resulting in longer fracture propagation caused by a significantly lower fluid-leakoff rate. This fluid loss system does not require the use of breakers, which eliminates the potential negative impact on post-stimulation well productivity. Laboratory test data will show the ability of the material to control fluid leakoff and its ability to achieve high levels of regained permeability to hydrocarbon. Field results from the application of the new system during acid fracturing treatments in high condensate gas producers in Saudi Arabia, in which achieving long half-length fractures with acid is very difficult due to excessive fluid leakoff, are also discussed. Post-treatment analysis showed that utilization of the new system resulted in significant reduction of fluid leakoff, thereby allowing treating pressure to remain above closure pressure throughout the treatment and achieve a longer fracture extension. A post treatment performance comparison between gas producers treated with the new system and those stimulated using conventional fluids will show that using the new system consistently exhibited better productionperformance (normalized for reservoir characteristics).
- North America > United States (0.94)
- Asia > Middle East > Saudi Arabia (0.67)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (4 more...)
Abstract During well drilling operations, the invasion of the porous media around the wellbore by a certain quantity of drilling fluid components is likely to happen to build a stable mudcake. For a horizontal open hole well, the mud cake is kept during drilling and completion operations giving stability to the borehole. Because the drilling fluid is heavier than the formation fluids, solid particles and fluid components are pushed into the formation establishing a filtration process. At some point, the mud cake must be removed and a clean up procedure is done. For production wells, the majority of the mud cake and invaded components are removed with the well production and the resulting skins are usually acceptable without any secondary treatment. However, for injection wells, such removal is always a problem and special treatments are needed. The success of such treatments is based on the knowledge of the invasion profile and their composition. Therefore, a better characterization of the invasion profile could improve substantially the clean up procedures and the treatment selection. In this first result the aim of study is to address this problem an experimental procedure was developed to identify and characterize the profile of drilling fluid invasion. This technique used the X-Ray Fluorescence Beam line (XRF) from the Synchrotron Light at the Brazilian Synchrotron Light National Laboratory (LNLS) in Campinas, São Paulo State, Brazil figure 1. This methodology allowed the determination of the invasion profile in synthetic unconsolidated sandstones similar in composition to the reservoir rocks. Along with the invasion profile, µ-SRXRF analysis was used to map and identify drilling fluid components that may have invaded the core. The identification of these components provided information to differentiate and identify carbonates and polymers in terms of concentration and penetration. The results obtained constitute a unique source of data and highlight the reliability and applicability of the technique proposed. Finally, a dimensional analysis was used to estimate the invasion profile for a real horizontal well. Introduction During well drilling operations, the invasion of the porous media around the wellbore by components from the drilling fluid is likely to happen. Since the drilling fluid is usually heavier than the formation fluids, their components are pushed into the formation, establishing a filtration process and building a stable mudcake. For a horizontal open hole well, this mudcake is kept during drilling and completion operations giving stability to the borehole. Fluid loss while Drilling is a complex process in which significant part of the fluid is lost underneath the bit under continuous spurt conditions[1,2]. The spurt loss occurs where new surface area is being generated, i.e. where the rock is being crushed and removed. Drilled fines, sized calcium carbonate, modified starch (HPA) and viscosified polymers (xantham gum), are filtercake compounds that cover the borehole. This filtercake is beneficial since it can significantly reduce the fluid loss rate preventing further collapse to the wellbore. During the spurt phase, however, fluid enters the formation resulting in potential damage,[3]. The depth of the invasion and the reduction in permeability in the invaded zone will determine the skin and overal1 effect on production.
- North America > United States (0.93)
- South America > Brazil > São Paulo > Campinas (0.24)
- South America > Brazil > Campos Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (22 more...)
Abstract A vertical well has a history of problems which has contributed to its disappointing performance. A 15 wt% HCl acid treatment was performed in an attempt to remove drilling mud filter cake and improve wellbore to formation connectivity, however the solubility of the formation's cementation material (calcite) was overlooked and sand production resulted after the treatment. A screen liner running operation was then performed, with a need for sand control, and massive mud losses and polymer pills were lost to the formation during the process. The workover fluids were displaced deep into the formation while loading the hole to maintain well control. The presence of biopolymers in the completion fluids enhanced the activities of sulfate reducing bacteria (SRB). These bacteria further compounded the problem, and the damaged environment was ideal to initiate the production of plugging FeS and biomass in the near wellbore region. Ultimately, the formation was not able to deliver the necessary flow rate to supply the ESP pump when the well was returned to production. The damage mechanism is a combination of polymer residue, biomass and FeS plugging the screen liner. A three-stage treatment was designed to remove the damaging material. The first stage was based on tetrakishydroxy methyl phosphonium sulfate (THPS) and was designed to remove iron sulfide and hydrogen sulfide, and control the growth of bacteria.The second stage was based on formic acid and was intended to remove FeS and some of the polymer residue in the near wellbore area. The third stage was based on a two-part oxidative treatment and was designed to remove polymer damage deep in the formation.Analysis of well flowback samples before and after the treatments was used to confirm the damaging mechanisms and to evaluate the treatment. This paper reviews the procedure used to identify the problem, and the unique treatment which successfully restored well productivity. Introduction Formation damage can occur during drilling, completion, or workover operations.[1–3]It can also occur during normal daily injection or production. Finally, it can occur during well stimulation treatments, e.g., matrix acidizing of sandstone and carbonate reservoirs.[4] Basically, formation damage causes loss of well performance, and usually requires an expensive chemical treatment to restore well performance. Formation damage can be divided into two main categories: mechanical and chemical.[5] Mechanical damage occurs when particulate solids, emulsion, asphaltene, or inorganic scales physically plug the pore spaces. A typical example of formation damage due to suspended solids occurs in water injectors.[6,7] Suspended oil droplets can also cause damage to water disposal wells, especially in the presence of suspended solids.[8,9] In both types of wells, suspended solids and/or oil can plug the formation in the critical near wellbore area, and cause loss of well injectivity.Details of various formation damage mechanisms were discussed by Civan3 and Nasr-El-Din.[10] Polymers are frequently employed in drilling, completion and stimulation operations.The polymers used are selected based upon their ability to provide viscosification, proppant transport and/or suspension, fluid loss control and zonal isolation.Yet the very properties for which they are chosen also make them difficult to break down following their application. Unbroken filter cake and insoluble high molecular weight polymer fragments are just two forms of damage produced by polymers.It is these residual effects of polymers that are responsible for reducing well productivity through damage to the formation. Some treatments require gel systems utilizing high polymer loadings in order to solve a present problem such as sand production, but the polymer becomes concentrated on the formation faces and causes some other productivity problems. At times the concentration of this polymer becomes so high that breaker additives are no longer able to thoroughly degrade it.The goal then becomes the reduction or removal of the polymer damage in order to obtain optimum productivity in a cost-effective manner.
- Asia > Middle East > Saudi Arabia (0.29)
- North America > United States > Texas (0.28)
- Geology > Mineral > Sulfide (0.80)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
Abstract Drill-in fluids are generally water-based muds containing a viscosifier, a fluid loss reducer, salts and sized calcium carbonate particles. Formation damage mechanisms induced by the use of water based mud formulations (WBM) have been extensively studied and correspond to different phenomena such as water trapping, polymer adsorption and retention, and particle plugging. In this paper, a detailed study was carried out on the behaviour of scleroglucan based formulations generally proposed for high temperature zone and/or high permeability reservoirs. In addition, a classical xanthan based mud was prepared and the performances of xanthan and scleroglucan containing formulations were compared. This work covers not only the effect of the fluid composition, including the presence or not of drilled solids but also the filtration conditions such as shear rate and temperature. Filtration curves obtained under static conditions can be related to the rheological behaviour and thermal stability of the biopolymer used as a viscosifier. These curves are not related to the solid content of the mud. Under dynamic conditions, the filtration curve strongly depends on the aggregation tendency of the scleroglucan sample. Mud filtrates have been characterized by multi angle laser light scattering coupled with size exclusion chromatography (SEC/MALLS). Characterization of the composition of the filtrate as well as the determination of the polymer molecular weight distribution, is very important to understand the formation damage tests performed on high permeability cores under downhole saturation conditions. Also, both the cake permeability and structure obtained by cryo SEM helped to understand the damage mechanisms observed with such formulations. Introduction Scleroglucan is a microbial and biodegradable polymer with high molecular weight whose chains assume a rod like triple helical structure associated by hydrogen bonds. As expected for a non-ionic polysaccharide, solution viscosities are independent of solvent quality; for this reason, multivalent ions have no effect on the rheological behaviour of polymer solutions. Up to 120°C, the polymer behaves as a semirigid chain. Scleroglucan was thus proposed as a better alternative to xanthan gum for drilling fluid compositions. Due to scleroglucan properties, such water-based formulations present higher potentialities specially in terms of hole cleaning capabilities i.e. suspension properties and carrying capacities. More recently, properties of such scleroglucan-based formulations were investigated to optimize formulations in terms of minimum fluid losses. The superior scleroglucan thermal stability at temperature above 100°C may lead to superior water-based formulations for such a temperature range. Optimised drill-in fluids formulations were already proposed for low permeability formations. In this paper, a detailed study was carried out on the behaviour of scleroglucan based formulations generally proposed for high temperature zone and /or high permeability reservoirs. In addition, a classical xanthan based mud was prepared and the performances of xanthan and scleroglucan containing formulations were compared. This work covers not only the effect of the fluid composition, including the presence or not of drilled solids but also the filtration conditions such as shear rate and temperature. Experiment Polymer stability Polymer solutions at 1 g/L in KCl 5g/L were aged in In conel cells under aerobic conditions for 16 hours at different temperatures (25, 60, 90, 120°C). Solutions were characterized before and after aging using a Contraves Low Shear 30 viscometer.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Seawater injection has been used to maintain the reservoir pressure in a carbonate reservoir in Saudi Arabia. However, the injectivity of some vertical wells in this field is limited due to low reservoir permeability (less than 20 md). Conventional matrix acid treatments did improve the injectivity to varying degree. However, to achieve the required injection rate, some of water injectors need to be stimulated by acid fracturing. Various acid systems have been evaluated to acid fracture injection wells. A thorough literature survey and lab testing eliminated acid systems that utilize acid-soluble polymers (both linear and cross-linked). This is mainly due to the formation damage associated with polymers, and also these systems required back-flow of the treated wells for cleanup. To eliminate formation damage due to polymers, flowback for cleanup, and to enhance well performance, a polymer-free viscoelastic surfactant fluid was utilized in acid fracturing treatments. The fluid system includes the non-damaging viscous pad and polymer-free leak-off controlled acids. The treatment was successfully applied in the field. Cleanup by flow back was eliminated with resulting in significant increases in well injectivity comparable to horizontal wells drilled in the same area. Introduction Many improvements have been made since the first commercial acid treatment in 1932, and acid fracturing is one among them. In acid fracturing, the fracturing principle is applied to increase the live acid penetration into the rock. It is an accepted practice to use a non-reactive fluid for fracture initiation and to condition the formation for maximum acid penetration. This will also help toprovide effective fracture extension due to controlled leakoff cool down the formation to ext end the reaction time for acid induce greater fracture width to reduce acid contact area and extend penetration saturate natural fractures and vugs to minimize acid leakoff. Generally, surface treating pressure is limited by wellhead equipment and tubing string. There are several reports on optimizing fracture designs by selection of fluids and injection rate though these are based on several assumptions. The effectiveness of any fracturing treatment depends on the fracture length and conductivity. The conductivity, in turn, will depend on the fluidloss, rock dissolution, and the damage associated with the treatment fluid. To control leakoff, industry has been using emulsions and acids gelled with polymers. Of them, polymers are the most widely used, though it is known for its stability limitations at high bottom hole temperature, especially in the presence of acid due to hydrolysis. Highly retarded acid-in-diesel emulsion that is stable up to 350°F has been developed and was found to be very effective in both matrix and fracturing treatments. Many carbonate formations contain micro-fractures (~ 5×10 inch wide) and during acid fracturing leak-off occurs through these micro-fractures as well as through the matrix. Acid can increase the permeability of these fractures several thousand-fold and the leak-off control is always a challenge. The fluid-loss could be controlled to some extent by the use of alternating stages of pad fluids and acids. Fine sand particles are also used in conjunction with polymers to help buildup filter-cake on the fracture surface and to clog the micro -fractures and interconnected vugs.
- North America > United States > Texas (0.68)
- Asia > Middle East > Saudi Arabia (0.49)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.47)
Abstract Injecting stable, preformed microgels as relative permeability modifiers to reduce water production minimizes the risk of well plugging or the absence of efficiency inherent to a technology based on in-situ gelling. Recent investigations showed that microgels formed by crosslinking a polymer solution under shear are soft, size-controlled, quasi-insensitive to reservoir conditions, stable over long periods of time and can control in-depth permeability by adsorbing onto all types of rock surface. The new laboratory studies reported in this paper aimed at knowing how to control the kinetics of crosslink formation by ionic strength and at determining the role the interactions between microgels on their propagation in porous media. The reported experiments include:gelling tests at different ionic strengths, measurements of viscoelastic properties of solutions, determination of both microgel density and microgel-microgel interaction parameter for different conditions of stabilization, the relation between the interaction parameter and the mode of adsorption of microgels. Partly attractive microgels were found to adsorb by forming multilayers and thus to induce drastic permeability barriers. Fully repulsive microgels adsorb as a monolayer and propagate easily in porous media at long distances depending only on the quantity of microgel injected. Thus, by controlling both gelling and stabilization processes, microgels can be produced to be either diversion agents or disproportionate permeability reducers to control water permeability at long distances from the wells. Introduction The reduction of water production becomes an increasingly important objective for oil industry, particularly because new environmental regulations impose severe limitations on the disposal of produced water. To reduce water production, a commonly used technique is to inject a polymer solution together with an organo-metallic crosslinker (1,2). The success of such well treatments would imply a good control of the in-situ formation of weak gels capable of reducing water permeability without affecting oil permeability. However, both gelation kinetics and final gel strength are very sensitive to the physico-chemical environment prevailing around the wells (pH, salinity, temperature, shear rates...). Since all these parameters cannot be known with the required accuracy, the results of such well treatments are hardly predictable: no gelling implies no effect on water production whereas the formation of a strong gel can affect drastically well productivity. To minimize these risks inherent to all well treatments based on in-situ gelling, we proposed to use soft, size-controlled "microgels" formed and stabilized before injection (3–6). Such microgels can be prepared on-site in a unit specifically designed to control precisely both shear rate during gelling and physico-chemical conditions. Ideally, microgels designed for water shutoff or profile control should be:insensitive to shear and reservoir physico-chemical conditions, size-controlled to prevent face plugging, small enough to ensure an in-depth treatment and large enough to reduce significantly water permeability, soft enough to be collapsed onto pore wall by capillary pressure in presence of oil flow in order to be disproportionate relative permeability modifiers, strongly adsorbing onto pore surface and stable over time, and non-toxic for the environment. Using non-toxic crosslinkers was a strong incentive to investigate the gelling properties of zirconium complexes (9–21). The main aim of this study was to improve the conditions of microgel formation and stabilization in order to obtain the properties required for different types of water shut-off operations. In the first section are described new gelling experiments carried out to elucidate the role of electrostatic forces on crosslinking kinetics. In the second section, the viscoelastic properties of microgel solutions are analyzed, giving information on the deformability of microgels under hydrodynamic forces. In the third section, the relation between the Huggins constant (a commonly used interaction parameter) and the propagation of microgels in porous media is established. In the fourth section, the behavior in porous media of fully repulsive microgels has been investigated. Finally, the main conclusions as well as the perspectives are drawn.
- Europe (0.68)
- North America > United States > Texas (0.46)
- North America > United States > Louisiana (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...)