|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
As the industry shifts from a high number of short-length wells to fewer, but longer lateral wells, the stakes are raised for operators as bigger does not always mean better and economies of scale are reduced. This article describes how the application of optically derived, in-situ measurements enables completion engineers to optimize the design and execution of frac operations and successfully reap the rewards of quality over quantity. The success of unconventional resources has changed the landscape of energy production globally. However, owing to the fundamental need to fracture otherwise impermeable formations and the inherently short productive life of frac wells, the economics of unconventional resources remains a capex intensive challenge. Operators are seeking the cost savings of reduced well counts, whilst achieving the same production with lower environmental impact.
A horizontal well completion method known as zipper fracturing has been rapidly adopted over the last couple of years by companies in the Eagle Ford shale of south Texas. Instead of drilling and hydraulically fracturing one well at a time, the zipper method involves drilling multiple wells from a pad site and then hydraulically fracturing a stage in one well, while getting ready for the next, as wireline and perforation operations take place in another. The multiwell completion method earns its name from the zipper-like configuration of the fracture stages from wells drilled with relatively tight spacing. This shaves days off the time it takes to complete a multiwell pad. Many companies in south Texas are now using the completion method on almost every new pad site they drill into, saving tens of millions of dollars per year while accelerating the development of their well inventories.
Propellant enhancement is a method of increasing permeability through the application of a transient high pressure event to the target formation. As distinct from hydraulic fracturing, propellant enhancement does not involve the application of chemicals or water and consequently does not present the potential for legacy environmental issues. This paper compares the regulatory aspects of propellant enhancement within the states of Australia and also the differences between environmental impacts.
A series of propellant enhancements were undertaken for a suite of gas wells in the Surat Basin, Queensland. Propellant charges in the range 18-30 kg were initiated, with deflagration times in the range 500-1,000 milliseconds. The compliance regime for the transport, storage and use of propellant is established under the state’s
There are three categories of fracturing used to increase permeability: explosive fracturing; hydraulic fracturing; and propellant enhancement. Explosive fracturing applies a very high pressure transient over a period of a few microseconds and can cause local, radial fracturing but with less desired compaction; hydraulic fracturing applies a lower pressure but over a longer period and with greater surface power, resulting in fractures that can extend 200-300 m, largely in the vertical plane; and propellant enhancement, which applies a mid-range pressure over a period of 10-1,000 milliseconds, resulting in fractures extending tens of metres but with random distribution. Residuals from the deflagration process are nitrogen, hydrogen chloride, water and carbon dioxide. There are no precursors for the BTEX suite and no conditions arising that could produce BTEX.
A prime question was to determine whether propellant enhancement is captured under the term ‘hydraulic fracturing’ in states’ regulations across Australia. Propellant enhancement is a technology with very few environmental impacts. Vehicular movements to support propellant enhancement are less than five percent of those to undertake hydraulic fracturing on the same formation. There is no requirement for waste water treatment.
One of the missing pieces for the Delaware Basin development in the Wolfcamp Formation is optimal spacing for horizontal wells. The spacing varies with formation characteristics (rock and fluid) across the Delaware Basin. A single method of determining optimal spacing has yet to be found as many pieces of information are still missing. Among the various parameters affecting development, well patterns and completion methodologies. Both parameters show a significant impact on the drainage area of wells and may in turn affect optimal spacing between the wells. The model outcomes are expected to improve recovery efficiency and minimize environmental effects of unconventional resource development. Several spacing tests were implemented in various areas of the Delaware Basin with multiple completion strategies. Private production and spacing data were analyzed in conjunction with data analytics. This step led to a newly developed model to optimize spacing. Various reservoir parameters such as permeability, fracture width and height, drainage area, reserves, and recovery factors were estimated according to patterns discovered by transient flow rate analysis.
These parameters may lead to an optimal spacing for the stacked Delaware Basin, and contribute to a better understanding of future neighboring wells development. Our findings and correlation within the Wolfcamp will be applied to various sections and formations across the Permian Basin. Current workflows and spacing advisors require use of numerical reservoir simulation and fracture simulation. Drainage area, reserves, recovery factors, and fracture height and width are the main unknowns in unconventional plays. Application of data analytics with production, spacing, life of the well on production, and completion data is anticipated to resolve some of these issues.
The paper is to develop a thorough understanding of well spacing and to propose a strategy for optimization in shale and tight rocks. Well interference due to fracture driven interaction (FDIs) (frac hits) may occur between neighboring wells especially if the distance between the wells are narrow. This interference must be avoided to reduce negative impact on productivity and estimated ultimate recovery (EUR) of the producing wells. The impact of these interactions is intricate and requires advanced numerical modeling to account for fracture propagation and depletion effects due to varied spacing sets (Kan et al. 2019).
Summary Researchers from both industry and academia have intensively studied tight oil resources in the past decade since the successful development of Bakken Shale and Eagle Ford Shale, and have made tremendous progress. It has been recognized that locating the sweet spots in the regionally pervasive plays is of great significance. However, we are still struggling to determine whether the dominant control on shale-well productivity is geologic or technical. Given certain geological properties, what is the best completion strategy? Most of the previous studies either analyze the completion data alone or divide the entire play into different data clusters by map coordinates and depth, which might neglect the heterogeneity in thickness and reservoir-quality parameters. In our study, we first conducted stratigraphic and petrophysical analyses, using the regional variation in depth, thickness, porosity, and water saturation to capture the regional heterogeneity in the Bakken Shale petroleum system. We selected approximately 2,000 horizontal wells, targeting the Middle Bakken Formation with detailed completion records and initial production dates during 2013 and 2014. Completion data inputs include normalized stage length (NSL), stage counts, normalized volume of fluid (NVF), and normalized volume of proppant (NVP). We investigated the relationship between the geological and completion features, and its effect on the first year of production. Then, we built a neural-network model to identify the relationship between the first-year oil production and the selected features. We separated the data into three sets for training, validation, and testing. After we trained the model using the training and validation set, we tested the model to estimate its robustness. Through sensitivity analysis, we demonstrated how the completion parameters combined with geological input would affect the production. The developed technique provides a method to identify the best well location, understand the effectiveness of the completion strategy, and predict the well production. Although the data used came from wells in the Bakken Shale, the methodology applies in a similar way to other tight oil plays.
Abstract Accelerating the learning curve in the development of the Vaca Muerta utilizing lessons learned in North American unconventional resource plays is the focus of this paper. Reducing completion costs while maintaining high productivity has become a key objective in the current low-price environment. Completion diagnostics have been demonstrated to optimize stimulation and completion parameters that have shaped successful field developments. The paper reviews stimulation diagnostic data from wells completed in the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara shale formations. Case histories are presented in which proppant and fluid tracers were successfully employed in completion optimization processes. In the examples presented, diagnostic results were used to assess the stimulation of high productivity intervals within a target zone, evaluate various completion methods, and optimize stage and cluster spacing. The diagnostic data were compared with post-frac production rates in an effort to correlate completion changes with well performance. Results presented compare first, engineered perforations versus conventional geometrically spaced perforations to drive up effectiveness in cluster stimulation. Second, new chemistries, such as nanosurfactant, versus conventional chemistries to cut either completion cost or prove their profitability. Third, employing an effective choke management strategy to improve well productivity. Last, as in any stacked pay, determining fracture height growth in order to optimize well density, well spacing, field development and ultimately the recovery of the natural resources. Completion effectiveness is shown to be improved by landing laterals in high productivity target intervals, increasing proppant coverage across the lateral by utilizing the most effective completion methods, optimizing cluster spacing and decreasing the number of stages to reduce completion costs while achieving comparable production rates. Cluster treatment efficiency (CTE), in particular, has become a critical metric when optimizing hydraulic fracturing treatment designs based on current and future well densities. It can be used to rationalize well performance as well as to identify possible candidates for a refrac program. Using completion diagnostics, successful completion techniques were identified that led to production enhancements and cost reductions in prolific plays such as the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara.
Abstract Plug and Perf (PnP) has been predominant for years as the preferred completion method for unconventional reservoirs. However this technique can be costly and time consuming. The Coiled Tubing Activated Frac Sleeves (CTAFS) technique utilizes fracture sleeves that can be hydraulically opened using coiled tubing and fractured through the annuls, minimizing time between stages and reducing total fluid consumption. This paper evaluates the fracturing and production performance of the Plug and Perf technique compared to Coiled Tubing Activated Fracture Sleeves (CTAFS) in a US shale oil play (Eagle Ford) and in tight sand reservoirs (Cotton Valley, Bone Spring and Granite Wash). It focuses on a strategy of improving ultimate recovery by using fracturing modeling, proper completion selection and field data to determine the optimal stage spacing of the multistage completion systems (PnP and CTAFS). The fracture models were created using existing logs and geomechanical modeling results in the surrounding area to create an optimal geometric spacing for the stages. The basics of the primary multistage completion systems are discussed and briefly compared from an operations point of view. Effective fracture dimensions can be achieved by selecting better locations for the stage clusters in Plug ad Perf and single fracture injection points using Coiled Tubing Activated Frac Sleeves (CTAFS). Fracture treatment schedules for each completion technique are recommended in terms of proppant type, concentration, fracture fluid type and volume. Two different fracture treatments were used to analyze the effect of fracturing fluid and completion type on fracture geometry. Coiled Tubing Activated Frac Sleeves with an optimized fracture treatment schedule outperformed the PnP as it fully controls fracture placement, leading to bigger drainage areas. For PnP, cumulative production decreased with an increasing number of clusters and the less efficiency of the stages on productivity. Adding more sleeves accelerated the EUR because of a larger drainage area. The CTAFS technique allowed tighter spacing of frac stages and ensured that the fracture was created at the sleeve in contrast to PnP technique in which some zones could remain untreated.
Swami, Vivek (CGG Services Canada Inc.) | Settari, Antonin (CGG Services Canada Inc.) | Sahai, Raki (Chesapeake Energy Corp.) | Costello, Dan (Chesapeake Energy Corp.) | Mercer, Ashley (Chesapeake Energy Corp.)
Abstract Many operators have used in the past various methods to analyze and optimize the horizontal well (HW) completions in the Eagle Ford play with varied results. Typically, such methods focus on different parts of this complex problem in relative isolation and as a consequence do not utilize all available data simultaneously. This paper presents a simulation-based method for analyzing the problem in an integrated fashion by modeling the fracturing and Stimulated Reservoir Volume (SRV) creation process, followed by well cleanup and production. Consequently, all available data are used to constrain the history match (HM), resulting in a more reliable tool for optimization. In this work, the authors developed a comprehensive integrated model of a typical Eagle Ford well in the Dimmit County. The HM process showed that injection and production scenarios must be modeled in tandem to get better insights into the flow physics rather than simulating them separately. The best accuracy is obtained when the real sequence of fracturing is modeled. It was found that only a fraction of the created fracture and SRV lengths contribute to production. Whereas fracture half-lengths of ~250 ft were generated during injection, only about ¼ of fracture and ¾ of SRV contributed. Effect of completion efficiency was also investigated. It was shown that the assumption of only 2 perforation clusters per stage is not plausible while assuming some other scenarios offers good HM and prediction very similar to uniform efficiency. Optimization work considered several scenarios. Cases with larger cluster/stage spacing with the same pumped volume are not desirable. However, the use of double the cluster spacing gives slightly higher estimated ultimate recovery in 30 years, and could offer significant completion cost savings. Use of current injection volumes and current well spacing (500 ft) leaves significant reservoir volume undrained, which is a target for well spacing optimization. Pressure (as opposed to stress) dependent permeability functions adequately capture the permeability variation both for injection and production. The work shows how the integrated reservoir/fracturing/geomechanics modeling can be used to optimize completions and EUR for shale wells.
Abstract Characterization of the lateral heterogeneity of reservoir properties is an important consideration during the design of horizontal completion operations in unconventional plays. Traditional geometric designs do not differentiate adjoining rocks based on lateral heterogeneity. This paper presents an academic case study from the Eagle Ford shale play in which the authors analyze and validate an engineering design using observations from an operator's completion design-based fracturing operation. The paper also proposes a low-cost, low-risk solution workflow for these unconventional reservoirs. An unbiased and repeatable fracture stage and perforation cluster optimization program was used for the engineered design. The input for the engineered design originated from a two-dimensional (2D) petrophysical and geomechanical model. This model was constructed using correlative property modeling that used openhole (OH) logs from an offset vertical well and a calibrated casedhole (CH) pulsed neutron log (PNL) that was acquired in the lateral. A conventional OH logging suite was also run in the same lateral, which was compared to the calibrated log data as a part of the validation process. The resultant 2D property model provided an appropriate representation of the subsurface reservoir properties. Lateral variations of those properties were duly addressed by optimizing the fracture stage and perforation clusters. This workflow also accounted for the relative position of the wellbore, with respect to the stratigraphic and the reservoir boundaries, as predicted by the 2D property model. During execution of the operator's completion design, reservoir properties were carefully observed and compared with those predicted by the 2D property model and the engineered design derived from the same. These observations validated the properties and justified the optimizations in the completions program and the modifications necessary. For example, a number of stages during the stimulation treatment were initially unsuccessful, thus allowing less than 10% of the total designed proppant to be pumped. During evaluation of the post-stimulation results, it was observed that these zones were identified as less promising by the 2D property model-derived engineered design because of unfavorable reservoir properties. The engineered design model recommended not completing these zones. The observations from this study showed that completion operations in a long lateral should be designed to account for the lateral variability of the reservoir. The engineered completion design optimized hydraulic fracture stages and perforation clusters based on the petrophysical similarity and merits of the adjoining sections. The methods presented helped mitigate risk and supported rigless operations for characterization in a cost-sensitive environment, thus reducing the costs and effects of hydraulic fracturing operations.
A horizontal well completion method known as zipper fracturing has been rapidly adopted over the last couple of years by companies in the Eagle Ford shale of south Texas. Instead of drilling and hydraulically fracturing one well at a time, the zipper method involves drilling multiple wells from a pad site and then hydraulically fracturing a stage in one well, while getting ready for the next, as wireline and perforation operations take place in another. The multiwell completion method earns its name from the zipper-like configuration of the fracture stages from wells drilled with relatively tight spacing.
This shaves days off the time it takes to complete a multiwell pad. Many companies in south Texas are now using the completion method on almost every new pad site they drill into, saving tens of millions of dollars per year while accelerating the development of their well inventories.
But the big prize may be that zipper fractures are increasing initial production and estimated ultimate recovery rates when designed so that the fractures stimulate the most reservoir volume possible. Tulsa-based WPX Energy, an independent operator of 160,000 acres in the San Juan Basin of New Mexico, told investors this summer that when the company switched to zipper fracturing, it averaged 420 B/D of oil production compared with 388 B/D from single-well completions. While not entirely sure if zipper fracturing is the direct cause of improved production, WPX said it expects that is the case.Mukul Sharma, a professor and chair in the petroleum department at the University of Texas at Austin (UT), said field data from Eagle Ford wells make it clear to him that zipper fractures are indeed improving initial production rates and the estimated ultimate recovery. Sharma said operators in south Texas have reported improved initial production rates ranging from 20% to 40% using the zipper method. “I would say that this is definitely the way people are going to be doing a lot of their fractures in the future,” he said. “What I think we need to do is understand better how it works— why it works. Once we understand that, we can apply it much more efficiently.”