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Degradable diverters are commonly used in multistage fracturing to increase the number of fractures along the wellbore and provide temporary isolation. Still, interpreting the effects of a diverter downhole remains challenging. In this paper, a nonintrusive monitoring technique is presented, which enables interpreting the effects of the diverter on multistage fracturing treatments. This technique relies on the processing of pressure data acquired at high frequency. Unlike other monitoring techniques, its deployment is straightforward and relies only on surface acquisition and interpretation algorithms. It does not necessitate any change or additional steps in operations by utilizing events which are part of fracturing treatments. Data are interpreted on-site and in real time, and the results lead to an improved understanding about the performance of the diverter downhole, the evolutions of the wellbore connectivity with the formation, and the degradation process of the diverter. The high-frequency pressure monitoring (HFPM) technique was used during several multistage fracturing operations. We present a case where the degradable diverter was used to effectively plug a leak during the fracturing treatment. The leak had inadvertently developed in a region of the well toward the heel, threatening the fracture stimulation stage aimed at the toe of the well. The HFPM technique was used to locate the leak, confirm its successful plugging with a degradable diverter, and monitor the degradation of the diverter. The HFPM provided control of the leak and data on when to pump additional diverter and the effects of the operation. The example demonstrates in a compelling manner that the HFPM technique enables real-time decisions that ultimately improve multistage fracturing treatments and operations relying on effective isolation and diversion. The HFPM presented herein is a novel, nonintrusive method for monitoring multistage operations and enabling real-time decisions. The technique is particularly valuable for monitoring treatments that rely on diversion and zonal isolation. HFPM is enabled by state-of-the-art signal processing and interpretation algorithms. It has the potential to become a ubiquitous technique that is part of each and every multistage fracturing treatment.

This paper describes the development and qualification of an oil-based gravel pack carrier fluid. The fluid is a water-in-oil emulsion prepared with base oil, brine, and emulsifier. Densities up to 13.6 lbm/galUS can be achieved using oil-to-brine ratios between 45:55 and 60:40. This oil-to-brine ratio range is such that the fluid exhibits low viscosity and Newtonian rheology, making it suitable for alpha/beta gravel pack placement. Extensive laboratory testing was performed to characterize fluid properties at various temperatures and oil-to-brine ratios. Performed in 4-in pipe, tests evaluated pressure drops at rates of up to 15 bbl/min, which revealed that the friction pressure generated by this fluid matches established empirical correlations for Newtonian fluids in turbulent flow. Finally, a full-scale yard test was performed to demonstrate that the fluid can be mixed using standard mixing equipment and used to successfully place alpha/beta gravel packs.

Advancement in fluid diverter technology has enabled successful initial stimulation of long interval carbonates without mechanical isolation, in excess of 1000 ft. by using in-situ crosslinked polymer systems and viscoelastic surfactant systems. These fluids build viscosity upon reacting with the formation, enhancing diverter performance. However, heavily stimulated, i.e. wormholed, formations require a step-level change in diversion performance to effectively stimulation new intervals, or previously under-stimulated layers. This paper will present the qualification and optimization of degradable fibers for use in re-stimulation of carbonate formations. The key performance aspects desired and evaluated are: (1) ability to block existing wormholes near the wellbore, as opposed to needing to fill the entire wormhole structure, (2) permeability and diversion capability of resulting fiber bridge, and (3) confirmation of degradation and cleanup in a dry gas environment within a reasonable timeframe. New experimental methods were developed to address these requirements, including gas/fluid degradation testing, bridging tests with slots to represent wormholes and fractures, and bridging experiments with 3D synthetic models of a wormhole structure. To be able to run repeatable experiments, wormholed structures were printed with a 3D printer using high-resolution CT scans from an actual wormholed core plug. Testing results showed the ability of the fibers to bridge within the wormhole network and provided guidance in designing the fiber diverter stages for already-stimulated wells. Addition of degradable particulates was shown to further improve wormhole bridging and diversion performance. Modeling the wormhole diversion process within advanced stimulation software identified additional optimizations, such as increased stage size and increased fiber concentrations to achieve desired diversion. A related presentation will discuss the successful re-stimulation of three high-rate gas wells (B. Clancey 2015).

Summary Dissolution kinetics of analcime (a zeolite), chlorite, and illite (layered aluminosilicates) are examined in hydrochloric and mixtures of hydrochloric and hydrofluoric acid systems. Dissolution kinetics were determined from batch reactor experiments in the temperature range of 25 to 100°C. The reaction progress was monitored by analysis of Al, Si, Fe, Mg, and Na concentrations in the aqueous phase. The reactivity of these aluminosilicates was compared with that of kaolinite under similar experimental conditions. Models for the reaction of the aluminosilicates with each acid are presented. The reaction kinetics incorporated into a geochemical simulator predict matrix-stimulation results for formations containing these minerals. Guidelines for design of matrixstimulation treatments for acid-sensitive formations are formulated.

Acid stimulation of sandstone reservoirs can lead to substantial production improvements of hydrocarbons and can considerably enhance the economic value of a well. However, this technique is still considered risky because of secondary and tertiary reactions between the spent acid and the rock. Precipitates resulting from these reactions can deposit in the pores of the rock and eventually negate the positive impact of the primary reaction. Being able to assess the extent of the secondary and tertiary reactions under reservoir conditions is therefore critical for the acid treatment success. Traditional methods to evaluate overall treatment impact consist of injecting acid through a short core and measuring the change in permeability. However, these methods only capture accurately the impact of the primary dissolution reaction. The much slower secondary and tertiary reactions occur over time scales greater than the acid residence time in the core, and therefore cannot be fully taken into account by these experiments. This paper presents a new and economical technique to assess the extent of those reactions under reservoir conditions. It relies on one or two experiments performed on short cores of 2.5 to 15 cm to determine surface areas of reservoir minerals. This information is then incorporated in a geochemical simulator. The simulator includes an extensive database of reaction kinetics and thermodynamics properties of various acids and by-products with the minerals commonly encountered in sandstone reservoirs. Radial flow, reservoir heterogeneities, and damage mineralogy are rigorously accounted for and allow one to scale up to reservoir conditions. The type, amount, and location of precipitates can then be determined. This information is used to optimize the stimulation treatment. This methodology was successfully applied to three treatments. - The first case study considers a well in the Gulf of Thailand. The high temperature of the formation, which favors precipitation of silica, and the high carbonate content were challenges for the design of the treatment. - The second case study considers a well in the Norwegian Sea. A high degree of reservoir heterogeneity had to be accounted for in order to scale up the treatment to reservoir conditions. Without prior acidizing experience in this formation, a reliable means of designing the treatment was required. - The third case study considers a well in the North Sea. The new technique was applied to determine the damage due to secondary and tertiary reactions from an acidizing treatment on a well in the Galley field, after operational issues caused the acid to stay in the formation over a long period of time. For the first two cases, various fluid formulations were tested and sensitivity analyses were performed to improve damage removal and minimize the formation of precipitates. The results provided accurate guidelines for the design of the treatments.

In multistage fracturing of unconventional formations such as the Eagle Ford shale, wells are traditionally stimulated by fracturing several perforation clusters simultaneously. While the technique is operationally efficient, there is evidence from production logs, microseismic monitoring, and other measurements that several clusters produce below expectations or do not produce at all. This condition is to a degree because stages penetrate zones with stress heterogeneities, and consequently, fractures propagate unevenly from all of the clusters. Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even further to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced fracturing technique has been developed based on a novel composite fluid comprising of degradable fibers and multi-sized particles that diverts the remaining stimulation fluids to understimulated regions of the wellbore. The composite fluid is delivered downhole at high-concentration, to create temporary plugs in clusters already stimulated thereby creating diversion with a minor amount of material. The solids degrade completely after the fracturing treatment has been completed, leaving no residual formation or fracture conductivity damage. The channel fracturing technique (Gillard et al. 2010) was chosen as the preferred fracturing method for use in tandem with the composite fluid. This technique has been reported to increase effective fracture length while reducing risk of screenout with respect to other conventional methods. The new composite fluid was used in a campaign where its effects were monitored with microseismic instruments. A case study presents field experiments where wells from the same pad are fractured in a similar fashion with and without diversion. In one application, with similar water and fluid volumes, the well treated with this technique produced more than 15% per stage than its conventionally treated offset well. The signature of the composite fluid, clearly visible on all measurement techniques, has proven consistent across stages of various lengths and wells having different characteristics.

The main challenge in acidizing multilayered carbonate reservoirs is to achieve optimum placement of the stimulation fluid. Optimum placement has often been interpreted as uniform placement of fluid across the producing interval, regardless of the objective of the intervention or its constraints. In addition, the current practice tends to design acid treatments based on information such as damage skin in each reservoir layer, which is rarely accurate. Therefore, a treatment initially designed as "optimal" often does not meet expectations because its design was based on erroneous formation and/or damage properties. We present an alternative approach to designing and executing matrix stimulation treatments in multilayered carbonate reservoirs. The proposed workflow does not rely on damage skin by layer during the design and the execution phases of the treatment. It instead requires a step of determining where the acid must be injected, at which rate and volume, to meet an objective function. This determination can be done considering an undamaged well, therefore relying on formation properties that can be measured with sufficient accuracy. How damage influences fluid placement is dealt with during the execution phase without relying on indirect parameters such as skin or local skin. Instead, by measuring the rate and volume of fluid injected in each layer, one can take the corrective actions that will ensure the placement of the optimal volume of stimulating fluid in the target layer(s), at the optimal rate determined in the design step. By using the objective function in conjunction with a fluid placement simulator, we show that different treatment objectives and/or constraints may require radically different strategies and tools for an optimal outcome. In addition, when carrying out a sensitivity analysis on parameters that are uncertain, it is possible to select the treatment that is most robust to variables that cannot be measured with accuracy (i.e., the treatment whose outcome is the least sensitive to uncertainties). The workflow we present here allows decoupling the questions of optimal placement of a fluid for a given well, the performance of the materials selected, and the treatment schedule considered. By using the optimum design and the objective function as guidelines, engineers can now take full advantage of real-time monitoring capabilities of tools such as fiber-optic-enabled coiled tubing or slickline, not only to take corrective actions during the treatment, but also to ensure that optimum volumes and rates are effectively delivered in the targeted zones to meet the stimulation objective. Case studies will be presented to illustrate this novel approach.

Hydraulic fracturing is a widely used technique for production enhancement. One critical property of a hydraulic fracture is the fracture conductivity, which has a direct impact on the productivity and hence, the economics of the stimulated well. Several laboratory techniques have been developed to characterize the materials that are placed in the fracture and influence its conductivity. Conductivity laboratory measurements have become a routine experiment with well-established procedures and setups aimed at simulating downhole conditions. However, correlating the performance of materials in a conventional laboratory setup with their performance in real conditions is not straightforward. This problem occurs because conventional laboratory setups are of limited length scale and fail to capture processes and variations that occur at a scale of the order of, or exceeding, the dimensions of the conductivity cell. Also, even if conventional setups provide accurate and reproducible measurements, they fail to provide fundamental, in-depth understanding of the actual processes that occur at the pore scale, occur in the fracture, and influence the fracture conductivity. A unique, large-scale X-ray computer tomography (CT) setup improves understanding of the factors influencing fracture conductivity. The state-of-the-art setup allows taking high-resolution scans of a proppant pack under conditions similar to an actual fracture. The setup provides unique insight into static and dynamic phenomena occurring at the proppant and the pore scale. The use of imaging software then provides an accurate 3D image over the entire length of the proppant pack. Computer models of flow in porous media can then be used to predict the flow and its parameters in the propped fracture and its porous network specified by the high-resolution images. Moreover, the setup scale (1 m long) is much larger than that of a conventional conductivity cell (20 cm long). The larger dimensions are adequate to capture heterogeneous processes such as fracture cleanup. The performance of the new setup was validated using baseline proppant pack conductivity and non-Darcy flow coefficients experiments. An example was also shown where the unique X-ray CT setup was used for investigating fracture cleanup of new, elongated rod-shaped nondeformable high-strength proppant compared with conventional spherical proppant. The CT images show how the new proppant provides a better fracture cleanup compared with spherical proppant. For both cases, images showing the distribution of residual gel saturation highlight how pore volume geometry affects fracture cleanup.

Recently, a new fiber-laden, self-diverting, and viscoelastic acid has been successfully used for matrix acidizing of highly heterogeneous carbonate formations The fibers have been designed to be inert under surface and pumping conditions, and their geometry allows them to form strong and stable fiber networks that can effectively bridge across natural fractures, wormholes, and perforation tunnels. Eventually, the fibers degrade into a water-soluble organic liquid that is produced back to the surface during flowback. In the case of perforated wells, experiments suggest that diversion with fibers operates in three phases. First, as the early volumes of fiber-laden acid reach the perforations, the acid penetrates the reservoir as if no fibers were present. Second, as the fibers bridge, they accumulate inside the perforations and form a fiber cake. Third, the fibers plug the perforation, and the injectivity decreases locally, promoting diversion into other perforations. The pressure drop through a plugged perforation was analyzed by performing 340 separate fine-scale 3D simulations. The original work was based on theoretical and laboratory-based experiments, considering typical perforation schemes and for various permeability ratios between the generated fiber cake and the formation's original permeability. The results were compiled, and a correlation was made to model the resulting skin. The model was implemented into an acid placement simulator and was extensively tested and validated in the field. In this paper, we present the model that describes the effect of fiber accumulation within perforations and explain how some of the model parameters such as formation-permeability contrast, fiber-cake permeability, and total permeability thickness (kh) may affect diversion efficiency. Case studies from field testing of the model illustrate methods of pressure history matching, job design, and treatment history evaluation.

Gas production from the unconventional Barnett Shale reservoir now exceeds 3 Bcf/d, which is more than 5% of total U.S. dry gas production. Typically Barnett Shale wells exhibit a rapid production decline following the initial hydraulic fracture stimulation treatment, so that, within 5 years, an operator is normally faced with a well producing below its economic threshold. To keep up with current gas demand, operators have moved to an aggressive horizontal drilling and completion program. Additionally, in an effort to increase the productivity of existing wells and book additional reserves at reduced cost, operators have restimulated their older vertical wells, with demonstrable success. This success is providing compelling opportunities to enhance refracture treatment coverage by targeting bypassed and ineffectively stimulated zones in additional vertical wells and even some horizontal wells. Because of the heterogeneous nature of this unconventional gas reservoir, the restimulation of horizontal wells is problematic, and operators have demonstrated limited success using current stimulation techniques. This paper describes a new fracture diversion technique particularly adapted for horizontal well refracture stimulation. During the treatment, a fracture diversion system (FDS) is used to create a temporary bridge within the active fracture networks. That results in differential pressure increase and causes treatment redirection to understimulated intervals along the lateral. This technique enables both fracture diversion without mechanical intervention and, when enhanced with microseismic monitoring, real-time optimization of the fracturing treatment. Refracture stimulation case studies are presented in which this novel diversion technique is successfully applied to horizontal Barnett Shale wells. This paper demonstrates how real-time hydraulic fracture monitoring has enabled operators to make informed decisions that influence fracture geometry, increase lateral coverage, and improve gas recovery. To date, more than 20 fracture diversion designs have been successfully placed. The trial wells have included both cemented and uncemented completions, with drilled azimuths selected to encourage either transverse or longitudinal fracture fairway development. With a continuing optimization of the described refracturing technique, these FDS designs and placement strategies have evolved to the point where they are consistently exhibiting fracture diversion as evidenced by movement of microseismic activity and improved lateral coverage. While this engineered fracture diversion technique is ideally suited for re-fracture stimulations, it is also applicable for stimulation of new wells where the technique enables stimulation of larger wellbore intervals when used in the same fashion as for re-fracture stimulation applications.

Self-diverting acids are commonly used in matrix acidizing treatments of carbonate formations, not only to increase permeability by generating wormholes, as with conventional acids such as HCl, but also to self-divert into zones of lower injectivity, in the goal of optimizing zonal coverage. In this paper, a new model for wormhole propagation is proposed, which describes both stimulation and diversion processes. A preliminary model is presented, which predicts wormhole propagation under radial-flow conditions for conventional acids. Then, a new set of parameters characterizing the reactive flow of self-diverting acids is developed, and the above model is extended to include self-diverting mechanisms. In particular, it is shown how the new parameters related to wormhole growth and those to diversion can be assessed from linear core-flood experiments and integrated into a new radial-flow model for field-scale prediction. Using this model, a new criterion is developed for diverter efficiency as a function of permeability contrast. Finally, the model is validated against radial flow experiments. It is found that self-diverting acids are characterized by two new parameters which, when combined with the model for wormhole propagation, can be used to predict the performance of self-diverting acids, both in terms of wormhole penetration and in terms of zonal coverage. Some criteria are also developed to assess the diversion ability of acids.

The wells in an oil field in East Venezuela have a bottomhole static temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in these wells. Currently, various formulations of mud acids, organics acids, and solvents are used to treat these wells with mixed results. A novel chemical system has been developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms, the new sandstone acidizing system (1) reduces the multiple stages in traditional sandstone acidizing to one stage; (2) minimizes precipitations by delayed and stabilized reaction mechanisms; (3) provides homogeneous dissolution of formation; (4) has a much lower emulsion and sludge tendency than conventional fluids as well as lower corrosion rate; and (5) stimulates sandstone reservoirs at high-temperature by effective damage removal and further matrix dissolution. Acid solubility, ion concentration, and mineralogical analyses indicate that the sandstone formation in this well has high content of iron-bearing minerals and a moderate content of sensitive clays. Results of core flooding tests conducted on the damaged field cores show that both mud acid and organic clay acid systems show secondary damage on the formation core sample during the acid preflush. Additionally, mud acid shows further damage after the treatment. In contrast, the new fluid system shows consistent damage removal during the treatment with the highest regained permeability. Geochemical simulations also show that more skin reduction is obtained with the new fluid than with the other conventional acid systems tested.

Challenges in sandstone acidizing still exist, although great improvements have been made in the last decade. Factors that contribute to these challenges include: multiple types of co-existing formation damage; uncertain rock mineralogy; multiple fluids and pumping stages; complex chemical reactions between fluids and formation minerals; and fast reaction kinetics at elevated temperatures. Others are: inadequate zonal coverage; limited live acid penetration; rock deconsolidation due to acid-rock interactions; acid emulsion and sludge tendencies; corrosion; and health, safety, and environmental (HSE) concerns. These factors contribute to the low success rate of sandstone acidizing treatments especially in acid-sensitive, and clay- and carbonate-rich sandstone formations at high temperatures.In this paper, we review some current practices used to address these challenges in the industry and present a new multi-pronged approach that would improve the success rate of sandstone acidizing treatments. The system requires the use of a geochemical simulator to "design for success" by selecting the safest fluid for the formation and for optimizing the fluid volumes and injection rates, and a breakthrough fluid that uses novel chemistry to simplify treatments and minimize the risk of acid-induced formation damage.Batch reaction studies indicate that the new fluid reacts more slowly with aluminosilicates than conventional mineral acids, thus preventing secondary and tertiary precipitates. Core flow tests demonstrate that the new fluid prevents the near-wellbore deconsolidation problems generally experienced with HF-based systems in high-temperature sandstone acidizing treatments. These laboratory results were corroborated with field core samples and geochemical simulations, especially with high-clay and high-carbonate sandstone formations.Extensive laboratory tests also demonstrate that the fluid results in less emulsion and sludge tendencies; lower corrosion rate to tubulars and equipment; better HSE footprint due to its almost neutral pH; and better tolerance to damage and formation uncertainties.

Formation water sampling is important for understanding corrosion and scaling potential of the water, characterizing hydrocarbon/water transition zones, determining compatibility between injection water and formation water, and determining optimal salinity and pH windows for polymer and gel injections. To obtain good quality formation water samples with wireline formation testers in wells drilled with water-base mud (WBM), it is important to track mud filtrate contamination by distinguishing between formation water and mud filtrate in real time while sampling. Current techniques typically use a resistivity sensor to monitor this contamination in real time. However, this works only when there is sufficient resistivity contrast between the filtrate and the formation water. Another technique involves addition of a colored tracer dye to the drilling mud and then monitoring the tracer concentration with an optical detector in real time. In this paper, we present results from a Middle East production well in which a new downhole pH measurement sensor was deployed on a formation wireline tester. The sensor uses pH-sensitive dyes that change color according to the pH of the water sample. The pH of the formation water is a key water chemistry parameter that can alter because of temperature and pressure changes surrounding the sample as it is brought to surface. Hence, to obtain accurate values, pH must be measured in real time at downhole reservoir conditions. In addition to successfully measuring pH downhole, results from this field test show that pH can also be used to qualitatively monitor mud filtrate contamination in real time. This takes advantage of the fact that the mud filtrate pH is typically much higher than the pH of formation waters. Multiple pH measurements during sampling showed a good match with cleanup trends determined independently using a colored tracer added to the mud. Simulations using some typical formation water and mud filtrate samples indicate that the pH dependence on contamination is a complex function depending on several factors including composition, buffer capacity, ion equilibria, ionic strength, temperature, and pressure. This makes quantitative estimation of contamination from pH measurements difficult; nevertheless, qualitative tracking of cleanup trends is possible and useful. The ability to differentiate between formation water and mud filtrate pH is also useful in characterizing oil/water transition zones and delineating oil/water contacts by scanning formation fluid samples at different depths. Both of these downhole pH measurement applications improve the efficiency and success rate of sampling with wireline formation testers.

Summary A new technique for characterizing secondary and tertiary reactions during sandstone-matrix-stimulation treatments is presented. In the new technique, traditional experiments on short reservoir cores are supplemented with measurement of the effluent-element concentrations, batch-reactor experiments, and geochemical simulations to predict the extent of secondary and tertiary reactions in the reservoir treatment. Alternative methods of characterizing secondary and tertiary reactions, such as those using long core flow tests and laboratory radial-flow setups, are reviewed. The new design technique is used in designing a treatment for a well in the North Sea. Details of how this technique was applied to the treatment design are presented. Post-treatment data from the well showed a successful matrix-treatment design. The production from the well increased by 1,400% immediately after the treatment. The 3-month stabilized production gain was 650%.