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Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
A leading cause of unsuccessful acid treatment is failure to contact all the damage with the acid. Fluids pumped into a formation preferentially take the path of least resistance. This makes the placement and coverage of the acid an important component of the treatment design. In a typical treatment, most acid enters the formation through the least damaged perforation tunnels, as the schematic in Figure 1 shows. When this happens, it can be readily concluded that acidizing does not work well and is expensive.
This work describes the positive results experienced when a self-diverting acid system based on a viscoelastic-surfactant (VES) technology was introduced for carbonate-reservoir stimulation offshore Brazil. The self-diverting (SD) VES (SD-VES) promotes viscosity development when the acid comes in contact with the carbonate formation. Since the SD-VES was introduced in this environment in 2009, more than 40 wells have been treated with the system. Matrix acidizing is frequently used to stimulate carbonate reservoirs offshore Brazil. In these treatments, a proper diversion technique is required to direct the treatment fluid to lower-permeability or more-damaged zones and ensure the treatment of the entire production interval.
Chen, Ming (China University of Petroleum, China) | Zhang, Shicheng (China University of Petroleum, China) | Zhou, Tong (Research Institute of Petroleum Exploration and Development, Sinopec) | Ma, Xinfang (China University of Petroleum, China) | Zou, Yushi (China University of Petroleum, China)
Summary Creating uniform multiple fractures is a challenging task due to reservoir heterogeneity and stress shadow. Limited‐entry perforation and in‐stage diversion are commonly used to improve multifracture treatments. Many studies have investigated the mechanism of limited‐entry perforation for multifracture treatments, but relatively few have focused on the in‐stage diversion process. The design of in‐stage diversion is usually through trial and error because of the lack of a simulator. In this study, we present a fully coupled planar 2D multifracture model for simulating the in‐stage diversion process. The objective is to evaluate flux redistribution after diversion and optimize the dosage of diverters and diversion timing under different in‐stage in‐situ stress difference. Our model considers ball sealer allocation and solves flux redistribution after diversion through a fully coupled multifracture model. A supertimestepping explicit algorithm is adopted to solve the solid/fluid coupling equations efficiently. Multifracture fronts are captured by using tip asymptotes and an adaptive time‐marching approach. The modeling results are validated against analytical solutions for a plane-strain Khristianovic-Geertsma de Klerk (KGD) model. A series of numerical simulations are conducted to investigate the multifracture growth under different in‐stage diversion operations. Parametric studies reveal that the in‐stage in‐situ stress difference is a critical parameter for diversion designs. When the in‐situ stress difference is larger than 2 MPa, the fracture in the high‐stress zone can hardly be initiated before diversion for a general fracturing design. More ball sealers are required for the formations with higher in‐stage in‐situ stress difference. The diverting time should be earlier for formations with high in‐stage stress differences as well. Adding more perforation holes in the zone with higher in‐situ stress is recommended to achieve even flux distribution. The results of this study can help understand the multifracture growth mechanism during in‐stage diversion and optimize the diversion design timely.
Bullet gun, abrasive, water jets, and shaped charges are perforating methods used to initiate a hole from the wellbore through the casing and any cement sheath into the producing zone. Bullet speed exiting the barrel is usually approximately 900 m/s (3000 ft/sec). Penetration is easiest in low alloy, thinner walled pipe [H-40, to K-55, and L-80 American Petroleum Institute (API) casing series pipe grades]. Penetration in higher strength casing alloy pipe and harder formations is more difficult in most cases and not feasible in others. When successful, the bullet creates a very round entrance hole but may often create a hole with sharp internal burrs.
Abstract In stimulated carbonate formations, one damage mechanism is the loss of near wellbore rock compressive strength upon matrix acidizing. Improper designed acidizing jobs may excessively soften the rock and negatively impact the mechanical response of near wellbore rock during production. In this work, an integrated geomechanical workflow is presented and applied to optimize acid placement and fluid diversion treatment in a Middle East carbonate reservoir. The model consists of petrophysical characterization of the formation, coupled wellbore flow model, rock dissolution model, rock physical model, wellbore stress analysis and lastly production prediction. The model first simulates stimulation fluid movement within wellbore and couples it with transient flow in reservoir. The primary analysis determines the distribution of reactive fluid along the well and predicts porosity evolution across the reservoir domain upon stimulation. Then, the developed geomechanical engine simulates the mechanical behavior (compressional or shear failure) of stimulated rock under different stress conditions during production stage. This paper introduces an integrated geomechanical workflow to stimulate matrix acidizing and describe dynamic reservoir compaction and its influence on production performance, which varies significantly with the stress condition, formation types and design strategy. In the presented case study, various diversion techniques are analyzed, and overall production are compared to assess the stimulation efficiency by considering the effect of rock failure. The comparative analysis identifies an optimized diversion technique and design, which can minimize near wellbore rock failure and sustain production for a longer term. This model enables a reliable prediction of acidic fluid distribution and identification of key controlling parameters to maximize conductive reservoir volume and mitigate premature wormhole collapse. Depending on the diversion technique and reservoir conditions, the workflow can provide a proactive solution to improve matrix acidizing design to enhance overall recovery. The presented case study can aid to build a customized and optimized strategy for matrix acidizing for middle east carbonate formations.
Abstract Ball sealers are commonly applied in fracturing and acidizing treatments for diverting treatment fluid to the desired zones by plugging perforations. It has proven that injecting ball sealers is a low-cost and efficient method for diversion. To predict the effectiveness of ball sealers, an improved ball sealer seating model is developed by introducing the maximum seating efficiency and random functions to capture the stochastic nature of ball-sealer plugging. The new model can predict ball sealer performance with different ball densities in vertical, deviated and horizontal wells. The traditional ball sealer model was originally designed for vertical wells, where ball sealers with different densities have similar behavior. However, for deviated and horizontal wells, the seating of buoyant and dense balls is more complicated. Buoyant balls tend to plug the perforations at the top of wellbore, and dense balls tend to plug the perforations at the bottom of wellbore. Thus, the traditional ball sealer model cannot be applied in these wells. A maximum seating efficiency for each ball is introduced in the new model, which is obtained by correlations based on experimental results. To describe the stochastic nature of ball sealer seating on perforations, a random number is assigned to each ball sealer, and a range is assigned to each perforation based on the ratio between flow rates through the perforations and flow rate in the wellbore. With the improved model, it can predict seating efficiency of ball sealers for all types of well with buoyant, neutral and dense balls. The results are showing that the seating efficiency of ball sealers predicted by the model can match the experimental results, which validates the model. Based on the simulation results, when ball sealers with mixed densities are pumped into deviated or horizontal wells, the seating efficiency is better than pumping ball sealers with only one density. For vertical wells, the benefit of mixing densities is minimal.
Scott, E. L. (Sigma Cubed Inc.) | Cape, J. H. (Sigma Cubed Inc.) | Mahrer, K. D. (Sigma Cubed Inc.) | Li, N.. (Black Hills Exploration and Production, Inc.) | Childers, A. R. (Black Hills Exploration and Production, Inc.)
Abstract This hydraulic fracture stimulation case study in the Mancos Shale, Piceance Basin used real-time microseismic imaging to evaluate and guide changes to diversion strategies. The objective was to identify and improve hydraulic fracture development of three neighboring, horizontal, and parallel wells. Black Hills Exploration and Production, Inc. (BHEP) hydraulically fractured three wells using a plug-and-perforate completion technique. All injection stages used the same treatment fluids and proppant types and differed by perforation schemes and diversion strategies. Diversion strategies included combinations of ball sealers and clean fluid sweeps (i.e., fluid without proppant), separating proppant-laden, ramped segments. Stages included one, two, or three proppant segments. The study included microseismic imaging, which acquired data using two deep geophone arrays in nearby wells. The microseismic data were processed during active injections (i.e., in real time). Following each stage, the on-site engineers compared the microseismic event distributions before and after diverters to evaluate diversion effectiveness. Differing microseismic distributions (e.g., changes in shape, azimuth, extent, etc.) combined with bottomhole pressure responses (e.g., increases and breakdowns) indicated successful diversion. Based on design, successful diversion strategies were repeated. Normally, an on-site engineer assesses diversion success using only the bottomhole pressure response. For this project, the assessment was substantially enhanced by combining bottomhole pressure response with microseismic imaging. As a result of this strengthened assessment, the on-site engineers concluded two main results during the study: (1) ball sealers separating proppant segments led to successful diversion and (2) a clean fluid sweep or a second set of ball sealers separating three proppant segments was less effective than two proppant segments. After identifying these findings, the engineers changed subsequent stages to include one set of ball sealers separating two proppant segments. In this study, reducing the number of proppant segments: (1) increased the stages per day by 10% and (2) increased the proppant load per fluid volume by 7%. In addition to these increased operational efficiencies and cost savings, this diversion evaluation and real-time changes improved perforation cluster efficiency (percentage of producing perforation clusters). For the three wells studied, production logs showed 3–24% greater perforation cluster efficiency than other local wells without diversion.
Abstract The use of mechanical diverters in the oil and gas industry has been common practice for decades. Perforation ball sealers, degradable balls, rock salt, dissolvable flakes, and downhole equipment such as sliding sleeves or straddle-packer systems are typical means for diversion. With the industry striving to grow more efficient, there is a need for a more permanent and reliable technology that can be deployed with ease and will seal previously stimulated perforations from untreated perforations. This paper will present a case history from two wells in the Wasatch and Green River formations that were treated with degradable diversion materials applicable at a broad bottom-hole temperature range. The diversion material used in both wells maintained its integrity under testing pressures and remained in place for the duration of the well completion operations. Biodegradable materials are applicable for multiple scenarios: zonal isolation for horizontal wells with multiple perforation clusters, through-tubing treatment of vertical wells in which bridge plugs cannot be used, sealing off perforations for re-stimulation treatments, and sealing off zones during lost circulation. The results from the two case-study wells treated in the Wasatch and Green River Formations provide compelling evidence that mechanical bridging agents can effectively replace bridge plugs and maintain zonal isolation in both new and re-fracture acidizing treatments. The concentrations of the diverter system blends were optimized during the treatments and achieved typical pressure increases of 200 to 600 psi per stage and completely sealed off the wellbore at pressures above 4,200 psi. The information presented in this paper will show the capabilities of using this material and the potential applications for multi-stage acid stimulation treatments. The pressure responses from the treatments and dissolution studies at specified temperatures show the ability of the materials to remain in place throughout the treatment of the well. The details of the successful treatment execution and the production results will be presented. The results of the case-study wells also show great advantages in both production and operational efficiency.