In water injector wells, continuous injection can wash gravel from the annulus around the screen, especially when injecting above the fracture pressure. The voids created after the annular washouts are sometimes filled by an influx of formation sand during shut-in operations. This sand accumulation consequently reduces the injectivity when the injection operations resume. A technique to prevent gravel washout was needed to maintain sand control and injectivity throughout the life of these water injector wells.
We therefore designed a product to prevent gravel washout by reinforcing the gravel pack with an interconnected network of fibers. The fibers contain a layer on the outside that is activated by temperature, forming a bonded fiber network that locks the gravel in place. This technique can be used with any type of proppant. The key benefit is that the fibers can withstand cyclic loading of stress during the shut-in and re-start of injection operations, which typically happen several hundred times during the life of an injector well.
Our experimental study to test this new product showed that the drag force of injected water easily displaced the gravel in the annulus into the fracture, whereas gravel reinforced with fibers withstood the drag force even at high injection rates (e.g., 100 bbl/d per 0.5-in-diameter perforation). We performed several more experiments to evaluate the strength of the pack under cyclic stress conditions. After 30 cycles, the pack strength was unaffected. The fiber chemistry was also adjusted for compatibility with commonly used fracturing fluids and brines. We found that the fibers remained connected in an interconnected network even after long-term interaction with sea water. We also studied the interaction of fibers with screens and other downhole equipment that come in contact with the fibers during gravel placement. The laboratory results of that study showed that the fibers did not create any issues with proppant placement or tool functionality during the sand control operation.
Our experimental study showed that the fibers provided an effective solution for preventing gravel washout in water injectors, thereby ensuring that sand control and injectivity remain as designed for the life of the well.
A Brown field has been in production for over 30 years. A redevelopment plan started in 2004 to revamp oil production under an Alliance partnership between an Oil & Gas Company Malysia and Schlumberger. The mentioned Brown field is a multilayered reservoir where the UCS can vary from 1500 psi in the consolidated sand until less than 800 psi in the shallow zones.
Based on a geomechics study and existing production history of the field, unconsolidated producer sands were identified and sand control methods were evaluated according to the degree of achieving the goals, and reducing risk, the result indicates that the Cased Hole Gravel Pack with Alternate Path System was preferential. Additional information was obtained in the latest campaign during the retrieval of gravel pack screens in 2 sand producing wells, which gave a better understanding of the failure mechanism in the previous gravel pack operations.
The main changes in the design of sand control systems during 8 years includes adopting a perforating strategy of performing a mechanical backsurge, increasing shot density and charges with low debris, use of a 3-way sub tailpipe system to avoid problems associated with breaking flapper valves and debris accumulation, number of cup packers, size of screens, slurry concentration and back pressure applied during the treatment. Furthermore the evolution in the sand control management have showed benefits such as increasing the number of gravel pack zones per well, performing longer gravel packs, installing permanent downhole gauges and using bigger tubing.
This paper presents as case study of the evolution and the impact of the sand management systems, showing the significant changes in the design and execution of gravel packs and describing the reasons for those changes. The impact is analyzed on the basis of formation damage, GP factor, execution, risks and results of the initial production.
Fluids with high viscosity are needed during hydraulic fracturing to convey the high pressure to create fractures in the rock formation, and to carry the proppant downhole to hold these fractures open after the treatment. A number of oxidative breakers, live and/or encapsulated, are usually mixed into the fluids upon pumping downhole to break the fluids after the treatment to flow back fluids and minimize the damage to the formation. It is not always easy to control the breaking rate of these breakers. If they break the fluids too early in the treatment, the fracturing fluids may not effectively create fractures, and screen-out may occur. Well treatment fluids for other oilfield applications may also require controllable slow-release rheology modifiers.
A novel rheology modifier has been identified recently and successfully used in a number of well treatment fluid systems. In one example, the rheology modifier can be used to break crosslinked fracturing fluids at desired rates. By adding the rheology modifier into the fracturing fluids prepared with the crosslinked polysaccharides, the fully controllable breaking of the fluids has been realized in our lab tests. In another example, the rheology modifier can be used to create a temporary plug that gradually self-breaks at a controllable rate. Low-residue and salt-tolerant hydroxyethyl cellulose (HEC) solution can be crosslinked into a viscous gel and used as a temporary plug. By including the rheology modifier at selected concentrations in the gel, the originally thick temporary plug can be gradually thinned to flowable fluid after the preset period of time. This way, the temporary plug can be easily removed from the wellbore after it has served its purpose.
The chemical mechanisms of the rheology modifier in the selected well treatment fluid systems will be discussed.
Acidizing in sandstone formations is a real challenge for many reasons, including: fines migration, sand production, and precipitation of reaction products.. Furthermore, the complexities of sandstone formations require mixture of acids and several additives. Recently, a new environmentally friendly chelating agent, Glutamic acid N,N-diacetic acid, was developed and extensively tested for sandstone formations. Significant permeability improvements were shown in our previous papers over a wide range of conditions. In this paper, we evaluate the results of the first field application with a fluid based on this chelating agent to acidize a vertical oil well in an offshore sandstone reservoir (target zone = 125 ft, temperature = 261?), with a substantial amount of corrosive gases in the form of seven percent H2S and three percent CO2.
The field treatment included pumping a preflush of 10 vol% mutual solvent and a 0.2 vol% water-wetting surfactant, followed by the main stage containing 25 wt% GLDA with 1 vol% of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of key cations were determined using ICP.
The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut or causing sand production. Analysis of flow back samples confirms GLDA capability to dissolve various types of damages while keeping the dissolved species in solution without causing un-wanted precipitation. Unlike previous treatments, where HCI/HF acids were used, the concentrations of iron and manganese in the flow back samples were negligible, confirming very low corrosion of well tubular and internals. The improved productivity, detailed flow back analysis and longer term performance results confirm the effectiveness of the new chelate as an effective sandstone stimulation fluid.
Crosslinked polymer hydrogels are commonly used in hydraulic fracturing to provide superior fracture width and length, while providing ability to suspend and transport high concentrations of proppant deep into the generated fractures. Then, during post-fracture cleanup, the gel viscosity must be reduced and the broken fluid flowed back through the proppant to the wellbore. This process should occur with minimal damage to the proppant pack so as not to restrict hydrocarbon production from the reservoir. Significant permeability damage to the proppant pack occurs if insoluble residue from the fluid becomes trapped within the pores of the proppant pack. Thus, it is of prime importance to ensure the fluid breaks cleanly and any insoluble residue is minimized.
A new, nearly residue-free fracturing fluid was developed for use in crosslinked fluid applications. This fluid system was found to be very clean, leaving little to no residue (<1%) upon breaking, leading to improvements in well cleanup and increased hydrocarbon production. This new fluid is a polysaccharide-based material which can be formulated to provide the necessary fluid performance parameters expected from traditional guar-based systems; but without the damaging insoluble characteristic of guar-based fluid systems.
A number of successful treatments utilizing the residue-free fluid have been performed resulting in superior production. This paper will describe the fluid system, laboratory testing and results, field operations best practices, and production data from a series of wells stimulated with the nearly residue-free fluid compared to offset wells.
Recent studies have offered evidence of unique shear viscosity loss of borate-crosslinked fracturing fluid viscosity when exposed to hydrostatic pressures, such as those encountered during deepwater hydraulic fracturing. This phenomenon can have important implications for proppant transport and for the resulting fracture geometry that need to be accounted for in fracture design. Another important aspect for fracture design is the fluid loss. Since crosslinked fluids have superior fluid loss characteristics compared to linear polymers, the question arises as to whether fluid loss of borate-crosslinked formulations is also affected by pressure. Fluid loss is a fundamental property in hydraulic fracturing treatments and may dictate the attainable fracture geometry and the retained conductivity. Prior knowledge of fluid loss is also important for designing special additives to overcome the effect of excessive fluid loss.
This experimental study was designed to determine the pressure effect on linear guar and both borate and zirconium-crosslinked polymers. The concept of melt temperature utilized for the viscosity dependence was incorporated to select fluids for this study. A unique high pressure, high temperature fluid loss apparatus was developed for the experimental testing. Test parameters varied from 160 to 260°F, 1000 to 9000 psi and 0.1 to 50 mD sandstone cores. Spurt and fluid loss coefficients were determined and compared to determine the pressure effect.
The results indicate that fluid loss behavior of fluids comprising borate-crosslinked guar is susceptible to pressure effects; however those effects are not as severe as the observations in viscosity loss. Conversely, the behavior for linear guar and derivatized guar crosslinked with zirconium were not influenced by pressure.
The implications of these findings for hydraulic fracturing applications are also discussed.
Zhang, Ke (Rice University) | Chanpura, Rajesh A. (Schlumberger) | Mondal, Somnath (University of Texas at Austin) | Wu, Chu-Hsiang (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Ayoub, Joseph A. (Schlumberger) | Parlar, Mehmet (Schlumberger)
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Sand particle size distributions (PSD) are used for various purposes in sand control: decision between various sand control techniques, sizing of the filter media (sand screens and/or gravel packs) through either rules of thumb or physical experiments or theoretical models. PSD of formation sand samples are also often used to generate "simulated" formation sand for laboratory experiments. The two most commonly used techniques for PSD measurements are sieve and laser, while some engineers use one technique for no obvious or justifiable reasons, others use both techniques for measurements and don't know what to do with the data when significant differences exist in PSDs obtained from each technique.
Lost circulation has plagued the industry since the beginning of drilling. Historically, severity of losses has been categorized based on the amount of barrels lost to the formation, i.e., seepage, partial, and total. Though helpful, this strategy doesn’t help understand the underlying drive mechanism(s) for losses and doesn’t provide enough data to propose a solution. The recently adopted category is focused on the lost-circulation mechanism based on the properties of the exposed formation; these
classifications are losses to 1) pore throats, 2) induced or natural fractures, and 3) vugs or caverns. This study provides an integrated workflow to predict expected losses for such classification/mechanism of losses.
Mud loss through fracturing is categorized based on fracture types, i.e., natural or induced fractures. Different models are used with respect to the fluid-loss mechanism in natural and induced fractures. These models take into account the effect of fracture breathing. In addition, mud loss through the pores on the wellbore and the fracture face is modeled based on formation and mud-cake filtration properties, coupled with the fracture losses. Losses to vugs/caverns are usually total losses due to very large openings in the rock; recommendations are provided on how to
control severe losses.
Lost circulation not only causes the adverse effect of mud loss itself; it can also lead to several other issues, such as formation damage, stuck pipe, hole collapse, and well-control incidents.The current industry trend is moving towards drilling more low-pressure zones, and lost-circulation planning is becoming a vital part of these projects. Knowledge of the type and the expected amount of mud loss can help engineers select the most appropriate and effective solution and preplan accordingly. This information also provides criteria to evaluate the effectiveness of the applied lost-circulation strategy. In this study we review LCM treatments, wellbore strengthening, MPD, and CwD as some of the most common remedial techniques.
Mexico, the world’s fourth largest producer of geothermal energy, generates 965 MW of electricity. One field alone produces 195 MW. However, to maximize the steam production of geothermal wells it is often necessary to perform matrix stimulation treatments. The temperature and mineralogy of the naturally fractured volcanic formations and scales tendency present some unique challenges.
The potential of many geothermal wells is limited by formation damage. Drilling fluid invasion, fines migration, silica plugging, and scaling being the most common. Mineral scale deposition occurs in the wellbore or in the natural fractures through which water is either injected or produced. In producing wells, the composition of scale is dependent on the mineralogy of the metamorphic formation. In injection wells, the scale is dependent on the composition of the injected water. With limited information regarding the mineralogy of the scale and the formation, many conventional matrix treatments are unsuccessful.
A hybrid design methodology, combining sandstone and carbonate acidizing techniques has proved to be the first step to successfully treating Mexico’s and Central America’s geothermal wells The treatments are then further customized for each field to optimize productivity and injectivity. The final fluid composition is often very different from that used in conventional treatments due to different selection criteria and placement techniques.
Identifying and understanding this concept has helped producers in Mexico and Central America increase their energy production per well by an average of 65%. While in some cases energy production has increased 300%.
The hybrid design methodology has been successfully used to stimulate more than 50 geothermal wells in Mexico and Central America - Humeros (Puebla), Tres Virgenes (Baja California), Berlin (El Salvador), San Jacinto (Nicaragua) and Azufre’s (Michoacan). The results of these campaigns demonstrate that it is possible to consistently improve the productivity of geothermal wells through the correct treatment.
As the stimulation of unconventional resources grows, there is a need for the development of alternative fracturing fluids that offer advantages over traditional guar-based fluid systems, particularly with regards to proppant pack clean up and the minimization of potential damage to the formation. As such, key parameters that would make a fluid system a preferable option over guar are the minimization of polymer necessary to achieve desired fluid stability, as well as the ability to perform in diversified water sources such as produced water. In order to meet this demand, a low pH fracturing fluid system which uses a low residue polymer as the gelling agent has been developed.
The new fluid system was designed to accommodate the needs of hybrid fracturing designs, and utilize water sources encountered on many locations. The linear gelling agent was selected that gives rapid hydration rates with water up to 100,000 ppm total dissolved solids (TDS) and at pH range of 5 to 11, eliminating the necessity of hydration buffers.
The crosslinked system offers effective fluid stability at pH 5 with a temperature range of 125 to 250 °F, reduced polymer loadings as low as 12 lbm/Mgal, and is stable in produced water of 100,000 ppm TDS up to 150°F. Linear gel systems also offer hydration rates of less than 3 minutes at 40°F in high TDS brines. This offers the advantage of minimizing the use of fresh water while maintaining a high level of performance.
This paper will discuss the distinct technical and operational advantages of this fluid system versus guar in various water sources, including produced water mixtures. In addition, data will also be discussed which indicates its impact on productivity and formation compatibility relative to currently used fluid systems.