Natural gas reservoir development continues at a record pace in North America. Additionally, reservoir pressure depletion and declining quality of reserves have resulted in escalating drilling, completion, and workover costs per unit of gas produced. This in turn forced industry to focus on increasing efficiency by refining completion processes and field operations to make wells commercially viable. Strategies such as multiple-zone commingled completions, the selection of fluids and additives to maximize hydraulic fracture effective length and conductivity, and fluid recycling/handling are but a few strategies employed. Additionally, operating companies have been seeking other cost-control measures, including reducing the number of additives in fracture fluids and minimizing disposal costs of produced waters by recycling and by using them as the base for completion and fracturing fluids. Because of the uncertainty of the produced water impurity, composition, and concentration, it is extremely challenging to make a fracturing fluid compatible with produced water. Together with the need to gel produced water, the demand for more conductive fractures, along with the capacity to create sufficient fracture geometry, has led to the development of a unique surfactant-based system relatively insensitive to most produced waters, and even to some high-density brines. Fluid chemistry modifications employed to enhance performance allowed for reductions in mix-water and fluid-handling costs, shortened flowback/cleanup time, and provided equal or improved post-fracture production response. This paper focuses on a description of the fluid chemistry and performance along with numerous fracture treatment applications with a variety of mix-waters.
Hydrocarbon production optimization in Pre-Salt carbonate reservoirs is a main focus for oil and gas research in Brazil. Stimulation treatment design optimization requires good knowledge of the reservoir properties and excellent understanding of the interaction between rock formation and treating fluid. This paper investigates these interactions through laboratory tests determining the compatibility of fluids used in matrix stimulation with different Pre-Salt carbonate rock types. The objective of this work is to relate the geology, petrophysics, and geomechanics of the Pre-Salt reservoirs to their expected stimulation response. Because of the difficulty in obtaining downhole cores and the destructive nature of most tests, the study focused on samples collected from a Pre-Salt carbonate analog: the Coquinas formation (Schafer 1973) from the Sao Miguel quarry, northeast Brazil (Chagas de Azambuja Filho et al. 1998). A thorough geology-based study of the Coquinas formation, including routine core analysis (FZI) microtomography, and thin section study was conducted. Usually these grain-supported carbonates show different amounts and types of primary porosity, closed and reopened by multiple diagenetic phases. Throughout the 25-m thick Coquinas reservoir, five rock types in 13 layers with permeability ranging from microdarcy to almost 1 darcy were identified. All rock types were subjected to routine mineralogy evaluation and various petrophysical, geomechanical, and spectroscopic measurements. Six of the thirteen layers were selected to perform core flow tests with a viscoelastic surfactant technology based diverting acid fluid (Al-Mutawa et al. 2005; Chang et al. 2001; Samuel et al. 1997). This is the first extensive study reporting the efficiency of a viscoelastic diverting acid system in the Pre-Salt analogue Coquinas carbonate formation outcrop cores. Spectroscopic measurement showed wormhole creation and, in some cases, rock texture alteration or fine migration. Through the study we identified the flow units and characterized the rock behavior when chemically stimulated. The conclusions from this study will enable us to tailor and optimize stimulation treatments of Pre-Salt carbonate reservoirs. Introduction The offshore Pre-Salt in Brazil comprises a group of recently discovered fields with promising oil reserves in the Coquinas formation or the above the microbialites section. For example, Lula (ex-Tupi) field, the lead field of the Santos cluster, is believed to hold between 5 to 8 billions barrels of oil equivalent (Beltrao et al. 2009). The Pre-Salt reservoirs are currently the focus of research in Brazil; however, the scarceness of downhole samples collected makes destructive tests very difficult to perform, and so analysis must be performed on analogues. The onshore Coquinas formation from northeast Brazil is taken here as analogue of the Pre-Salt carbonates.
The extent of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment. In certain cases, excessive crosslinking while the fluid is in the tubulars can result in friction pressures that are too high, and may prohibit the treatment from achieving the design goals. With titanium (Ti) or zirconium (Zr) crosslinked gels, which are known to be prone to irreversible shear degradation, early crosslinking in the tubulars can substantially reduce the final gel strength, even to the degree that near wellbore proppant transport is compromised, and the treatment may screenout. On the other hand, a Ti or Zr crosslinked gel which crosslinks substantially after exiting the perforations may not have sufficient proppant transport capability to complete the treatment successfully. Varying treatment conditions such as mixwater composition and temperature, tubular shear rate and transit time, and reservoir temperature pose difficult challenges to routinely achieving the optimal crosslinking state. Conditions such as offshore wellbore temperature profiles and viscous heating in smaller diameter tubing can further complicate the task. Various chemical means have been employed to tune the crosslinking temperature for specific treating conditions. These methods involve addition of chemicals to control the crosslinking kinetics, such as pH buffers, crosslinker concentration, and competing ligands to temporarily bind the metal crosslinker. Blended crosslinkers containing a single Group 4 (Ti, Zr) metal with different organic ligands with different binding strengths have been employed to achieve crosslinking at two temperature ranges so that early viscosity for proppant transport can be developed. Mixed metal crosslinkers, such as aluminum and Zr have also been formulated for this same purpose. This paper examines the disadvantages of these strategies, and describes the development and deployment of a high-temperature fracturing fluid system that has shown to overcome those issues. Introduction Achieving the design fluid viscosity at in-situ conditions is critical for a number of reasons. Fracture initiation, propagation, and resulting dimensions are strongly influenced by the viscosity. Proppant transport, also determined by fluid properties, is necessary for fracture areal coverage and helps determine well performance. Overcoming the various demands on a gel formed from a single organometallic crosslinker are difficult to achieve (Fig. 1). Ideally, the crosslinking could be triggered instantaneously just after the fluid exits the perforations, avoiding high friction pressure and degradation resulting from shear in the tubulars and perforations. Crosslink the fluid too early and the friction in the tubulars will rise significantly and, as it will be shown later, a significantly crosslinked fluid cannot be sheared without permanent damage to the polymer molecular weight, and therefore to the fluid viscosity. Low initial viscosity from crosslinking too late may result in a narrow, near-wellbore fracture, impeding proppant transport. Either crosslinking a single organometallic system too early or too late risks premature screenout. (Nolte 1988, Walser 1988, Almond 1984) Gelling at varying temperatures can be achieved by delivering a crosslinker that has two (or more) organometallic complexes: one that could yield limited crosslinking at a lower temperature for initial proppant transport, and the second complex for higher temperatures experienced in the fracture. This approach would manage friction pressures. However, the gel would still suffer irreversible degradation due to the strong metal bonds existing during high shear in the tubulars.
Unconsolidated formations and high permeability reservoirs are susceptible to fines migration. The main contributing factors are high formation fluid velocity, wettability alteration, change in water salinity, and rock failure. Typically, fines migration problem occur in the near-wellbore vicinity due to high drawdown pressures. Depending on the severity, it can result in rapid productivity decline, erosion damage to downhole and/or surface hardware, and surface facility upsets.A properly designed frac pack frac pack can mitigate the migration of fines if it is indeed a problem. However, as insurance there are some technologies currently used to address fines migration in frac packs. These technologies have some limitation such as only being designed to treat the fracture but not the near-wellbore vicinity, prone to causing long-term damage to proppant pack conductivity, and needing remedial work to cleanup the proppant pack followed by retreatment.In this paper, we will discuss the development of a new technique that effectively controls the migration of fines both within the formation surrounding the near wellbore as well as fracture area, and which does not affect proppant pack conductivity. We first detail the laboratory testing program followed to develop this technology including synthetic pack fines migration core flow evaluation, compatibility with frac-pack fluids, proppant pack and formation damage. Thereafter, we discuss the field deployment process and compliment with case histories. The laboratory results demonstrate that fines migration in the synthetic pack is drastically reduced with this new technique, that the technique is applicable up to 280°F, and that it can be deployed in commonly used frac-pack fluids. Production results of treated frac-pack wells have met expectation and after a year no fines production has been reported.
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures. This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties -such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson's ratio and Young's modulus -on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design. This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young's modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.
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