Search

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).

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.

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.

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.