Searles, Kevin H. (ExxonMobil Upstream Research Co.) | Zielonka, Matias G. (ExxonMobil Upstream Research Co.) | Ning, Jing (ExxonMobil Upstream Research Co.) | Garzon, Jorge L. (ExxonMobil Upstream Research Co.) | Kostov, Nikolay M. (ExxonMobil Upstream Research Co.) | Sanz, Pablo F. (ExxonMobil Upstream Research Co.) | Biediger, Erika (ExxonMobil Upstream Research Co.)
This paper describes the development, validation, and application of new 3D finite element models for a diverse set of oil & gas problems involving fluid-driven fractures. Applications described in the paper include borehole integrity and lost returns, drill cuttings re-injection (CRI), and produced water reinjection (PWRI).
The models were developed and implemented in a commercially available finite element (FE) software package. The models include both cohesive elements (mesh conforms to pre-defined fracture orientation) and extended finite elements (fracture geometry evolves independent of the finite element mesh). Advantages and disadvantages of each approach will be described. The models were validated through comparisons with published analytical asymptotic solutions for limiting values of rock and fluid properties and leak-off conditions (with practical problems of interest lying within these limits). A comprehensive suite of large-scale laboratory experiments were also conducted and models were used to replicate the conditions and results of these experiments. Larger 2D and 3D finite element models were then constructed and used to demonstrate applicability to a broad range of realistic oil & gas problems, including problems with large length and long time scales. Tractable simulation of these problems was enabled by high-performance, massively parallel computing systems.
The models show excellent agreement with published analytical solutions for a broad range of rock and fluid properties and fracturing conditions. The models also show reasonable agreement with laboratory experiments for a similar range of conditions. The models scale up from lab to well scales and have shown practical applicability for a diverse set of challenging oil and gas problems.
Most hydraulic fracture models fall into the categories of fast-running but with simplified physics, or complex physics but computationally impractical for full-scale commercial applications. The models described in this paper have been applied at commercial time and length scales, but also provide for full representation of the complex physics of hydraulic fracturing, as demonstrated by the comprehensive validation with analytical solutions and laboratory experiments.
Recent analytical models for abnormal and normal leakoff mechanisms of the pressure falloff behavior in fracture calibration tests (DFITs) provide means to match virtually all of the behavior. The match provides both the parameters related to normal leakoff behavior including closure pressure and the leakoff coefficient as well as abnormal leakoff parameters including tip extension distance and minimum fracture propagation pressure, closure pressures, leakoff coefficients, and leakoff areas for the coupled primary and secondary fracture system. The purpose of this paper is to provide a methodology for identifying these behaviors and quantifying all of the before closure parameters of interest to design of the main fracture treatment.
We use the behaviors seen on the log-log Bourdet and the G-function derivatives to identify a sequence of flow regimes and to estimate starting values for the parameters associated with each leakoff behavior. Simulation result with these starting estimated values are able to catch all identified leakoff features. Then we adjust the parameter starting values to achieve a global smooth match for the falloff data.
Equations developed for quick estimation of the starting values facilitate the model match with data. Several field cases with pressure dependent leakoff (PDL), tip-extension, multiple-closure phenomenon and transverse storage are taken as examples to illustrate the comprehensive modeling capability. The additional parameters quantified by this methodology have their reasonable physics and greatly enhance understanding of the role of tip extension and the induced secondary fracture system in the hydraulic fracture stimulation.
Cement bond logs were compared to downhole pressure and temperature gauges to understand the relationship between cement bond quality and communication between stages during horizontal fracture stimulation in a tight sand formation.
Fracturing was performed using a coiled-tubing-conveyed packer and sleeve system inside cemented casing. Pressure and temperature were recorded above and below the packer to measure communication between stages. In three wells, ultrasonic imaging tool (USIT) logs were run prior to stimulation to analyze cement bonding 360° along the lateral. USIT log evaluation, gamma ray logs and recorded pressure and temperature data were evaluated to determine the correlation between cement bond and stage isolation.
In one well, the bond log showed no cement bond in approximately half the lateral. With no other form of isolation behind pipe, communication between stages would be expected. There was virtually no communication, however, between stages according to the pressure and temperature gauge data. In the other two wells, the bond log showed excellent bond quality, but communication was seen on the bottom-hole pressure/temperature gauge during several fracturing stages. These counterintuitive results initiated further evaluation. Gamma ray logs were compared to the pressure and temperature data to determine if there was a stronger correlation between stage communication and rock quality. Other qualities of the frac design were also investigated. The results indicated that rock quality in combination with stage spacing have more of an impact on stage communication than cement bond quality. These findings have since been used to determine optimal stage spacing and to support a shift from cemented to open-hole completions.
Motiee, Monet (Hess Corporation) | Johnson, Maxwell (Hess Corporation) | Ward, Brian (Hess Corporation) | Gradl, Christian (Hess Corporation) | McKimmy, Michael (Hess Corporation) | Meeheib, Jeremy (Calfrac Well Services)
Traditionally, friction reducer systems have been used to promote laminar flow in pipe to reduce friction pressure in pumping of low viscosity, slickwater-type fracture treatments. In these types of treatments, velocity is the key factor in proppant transport into the reservoir. Typical testing of these conventional friction reducer fluid systems focuses primarily on the chemical's ability to reduce treatment pressures and permit higher fluid velocities.
In an effort to reduce completions costs and improve operational efficiency while maintaining baseline well productivity, our Completions Team applied these conventional friction reducers in an unconventional way. The project used high concentrations of friction reducer (HCFR) as a direct replacement for a guar-based borate crosslinked system without modification to the standard treatment and proppant schedule. The team took steps to qualify the fluid for field implementation, including low shear rate viscosity testing, proppant settling testing, and regained conductivity testing.
Following qualification and operational planning, the team performed field trials. The data showed a reduction in footprint and overall horsepower requirements. The reduced volume and number of chemicals on location led to decreased exposure to hazardous chemicals and also simplified logistics, resulting in fewer truck movements on location. The reduction in chemicals impacted the economics of the well completion positively. The stimulation costs of the wells treated with HCFR when compared to the wells treated with the baseline fluid design showed a chemical cost reduction of approximately 22% per well.
In addition to the cost and operational efficiency benefits observed in the project, initial production data indicates that the wells are meeting or exceeding baseline productivity curves.
Wallace, K. J. (Encana Oil & Gas (USA) Inc.) | Aguirre, P. Reyes (Schlumberger) | Jinks, E. (Encana Oil & Gas (USA) Inc.) | Yotter, T. H. (Encana Oil & Gas (USA) Inc.) | Malpani, Raj (Schlumberger) | Silva, Felipe (Schlumberger)
This paper describes a comprehensive field study of eight horizontal wells deployed in the stacked Niobrara and Codell reservoirs in the Wattenberg oilfield (Denver-Julesburg basin). The overall goal was to understand the geometry of the hydraulic fractures (propped), producing volume with respect to completions design, target reservoirs, and well spacing. Through this understanding we are able to develop the asset more effectively and economically.
In this study, an unconventional hydraulic fracture model was developed and calibrated against surface and downhole microseismic recordings, "frac hits" in offset vertical wells, chemical tracers, pressure interference testing, diagnostic fracture injection tests (DFITs), and treatment pressure/instantaneous shut-in pressure (ISIP) history matching. The hydraulic fracture geometry and conductivity were simulated using unconventional models populated with a natural discrete fracture network (DFN) defined through outcrop and image log observations along with a rigorous mechanical earth model.
A special unstructured grid that conforms to the shape of the calibrated hydraulic fracture model planes was constructed. This unstructured, fractured reservoir grid was fed into a compositional reservoir simulator that was tuned using pressure dependent permeability, offset vertical well pressure depletion, and relative permeability (among others) to match the production history available to date.
This workflow allowed for complete integration of geological, geomechanical, and production models in a single platform to produce a consistent set of results. This study concludes that 1) Increasing the hydraulic fracture treatment volume beyond a certain point does not significantly enhance the fracture geometry or improve early time well performance; 2) additional wells are needed to access undrained reservoir; 3) existing vertical-well depletion has a significant impact on early time well performance, and; 4) hydraulic fracture height extension allows initial communication between the Niobrara and Codell reservoirs, however this connectivity dissipates during production likely due to the loss of fracture connectivity vertically.
The struggle to define an optimized completion strategy remains a significant challenge in unconventional multistage horizontal wells. Stage and cluster spacing is a design decision that often requires significant experimentation to determine what is the optimized spacing of propped fractures that efficiently drains the reservoir yet can be reliably pumped to completion. This paper illustrates the importance of bottomhole (BH) gauge data for evaluation of stage and cluster spacing and general completion quality. The knowledge derived through careful analysis of this valuable data source, can significantly reduce the amount of experimentation typically required in other completion techniques. Consequently optimized field scale completion strategies can be refined with efficiency and reduced overall costs.
Coiled tubing (CT) assisted hydraulic fracturing (HF) is a good alternative to the standard plug and perf completion in multistage horizontal well stimulation. During a CT HF operation, fracturing is initiated via pre-installed frac sleeves or sand-jetted perforations. One of the advantages of CT fracturing is improved target fracturing, where a single-entry fracture initiation point can be placed at the desired depth to target the best rock for stimulation. Another benefit of CT fracturing is the ability to gather BH treating pressure via BH gauges (BHG) mounted on the CT bottomhole assembly (BHA). Bottomhole pressure and temperature gauges, installed above and below the isolation packer, provide valuable information about fracture communication between stages, cement integrity and stress shadowing.
This paper will review dozens of CT frac jobs performed across various basins in North America. Information obtained from BHG is merged with surface treating pressure and other diagnostic data sources and subsequently analyzed. One key area of analysis is to examine stage communication data for stress shadowing effects. The primary takeaways from this paper are to illustrate the importance of BHG data, how it compares to other diagnostic data, and how it can be analyzed to effectively drive the stimulation design process.
Refracturing in the US midcontinent is not a new method. In 1980, a refracturing program was begun in the shallow, low-pressure Brown Dolomite gas pay in the Texas panhandle. The results were mixed, but the overall outcome was economically beneficial. Currently, operators are refracturing horizontal shale wells, especially those completed from 2003 to 2010. However, results continue to be mixed and unpredictable. This paper presents lessons learned during refracturing treatments performed between 1980 and the present that led to the creation of a new approach to refracturing treatments.
This paper discusses the factors to consider when planning a refracturing program. Refracturing failures are also discussed as a means to understand the controllable and uncontrollable variables that lead to these failures. Failures are categorized and specific failure types and modes are identified. Examples of successful refracturing treatments are also included.
The resulting newly developed refracturing approach includes a four-step process:
Candidate identification Refracture diversion design Execution and diagnostics Production analysis and diagnostics
Refracture diversion design
Execution and diagnostics
Production analysis and diagnostics
Examples of using the four-step process are provided to show the incremental improvements that resulted from identifying potential candidates and designing, executing, and analyzing the project. Production results and incremental estimated ultimate recovery (EUR) values are discussed to illustrate the economic viability of refracturing, and the economic benefit of this incremental production increase is compared with the cost of the refracturing treatment. While incremental production from refracturing in the midcontinent has more than doubled, pre- and post-fracture diagnostics should improve the success rate by defining lateral coverage. Real-time diagnostic techniques are discussed as potential tools for pre- and post-refracturing analysis.
Despite the history of mixed results, refracturing efforts are improving through the implementation of this new four-step approach. Repressurization of the original fracture system is common to successful refracturing throughout time. New diversion materials and placement processes help achieve repressurization and refracturing placement success. Also, additional insight from new diagnostic tools and techniques can help improve the overall refracturing project success.
Many studies have assessed microseismic (MS) interpretation, and its source mechanisms in hydraulically fractured shale wells. However, the ability to derive stimulated reservoir volume (SRV) and fracture geometry from MS data is still controversial. This is because MS events not only come from the induced main fractures of the current stage, but they also result from reactivation of natural fractures (NF) or faults, previous hydraulic fractures (HF), stratigraphic boundaries, or other operational noise. MS data of adjacent stages tend to overlap each other severely, masking the real SRV of the current stage. Simulated complex fracture networks using MS data always yield higher production results when compared to actual production. We address these issues with an efficient MS interpretation method.
This method divides the MS events into three windows using an Excel-VBA program: the Pad Window, the Proppant Window, and the Closure Window. These windows are based on the fracture stimulation job record for each stage. The Closure Window includes only the events from the end of pumping until the end of shut-in of the current stage. During the Closure Window, i.e., shut-in time before flowback, leakoff into the formation matrix can cause micropores to enlarge, resulting in MS events with compensated linear vector dipole (CLVD) and isotropic (ISO) sources (crack opening mechanisms). Leakoff can also cause slippage of pre-existing NF and result in MS events with double-couple (DC) source. These fractures are secondary fractures with potential to transport fluid and facilitate the induced major fractures. When all of the fluid leaks off at positions along the main fractures, the fracture will close, which may trigger MS events with CLVD and ISO source mechanisms.
We extracted the MS events in the Closure Window and eliminated those events induced by previous stages, NF, and pumping noise. Thus, we reduced the MS cloud overlap of different stages and increased the accuracy of the inferred fracture geometry and SRV. Case applications on several shale wells were used to test this method. On the basis of the results, we suggest continued monitoring MS events after the end of proppant pumping.
The method developed in this study can process any MS data and the associated fracture stimulation job data to segregate the three MS event windows. The Closure MS Window will indicate fracture geometry more accurately, and thus enhance optimization of hydraulic fracturing design and the prediction of hydrocarbon production.
With the large number of fracture stages, and size of jobs being pumped in horizontal wells, many companies have elected to use non-standard, or non-commercial natural sands as propping agents. The Stim-Lab Proppant Conductivity Consortium, supported by approximately 50 proppant suppliers, pumping service companies and operators, has developed consistent laboratory conductivity test procedures over the past 30 years that have become de-facto industry standards. One outcome of this long history of proppant testing is a set of correlations that can predict the baseline conductivity, as a function of closure stress and rock (substrate) properties, within the range of uncertainty of laboratory tests. Inputs to the correlations are basic material property measurements such as specific gravity and median particle size of the sieve distribution. The correlations can be used to compare materials of unknown properties to standardized data sets, or to develop useful predictions of how a non-standard material is likely to perform. The correlations are general enough for application to brown sand, white sand, resin-coated materials, and ceramic proppants of various sizes and densities. These correlations have been found to be sufficient for comparing proppants and for estimating their performance in production computations, when adjustments for appropriate damage and cleanup are made to the calculated baseline conductivity values.
Ugueto C., Gustavo A. (Shell Exploration and Production) | Huckabee, Paul T. (Shell Exploration and Production) | Molenaar, Mathieu M. (Shell Exploration and Production) | Wyker, Brendan (Shell Exploration and Production) | Somanchi, Kiran (Shell Exploration and Production)
It is now well established that the production from horizontal wells completed via hydraulic fracture stimulations (fracs) is highly variable along the length of the wellbore. In addition to subsurface conditions, elements of the completion design, such as fluid volume, proppant tonnage, rate, stage length, the number of perforation clusters and their spacing, influence the performance of individual stimulated intervals and wells. Information about completion efficiency can be obtained using Fiber Optic (FO) diagnostics. Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) provide great insights into the factors controlling frac construction and performance of each perforation cluster. The integrated analysis of DAS and DTS in horizontal wells completed with multiple perforation clusters per stage indicate that, although most perforation clusters receive fluids during the stimulation, there are significant changes in efficiency during the frac stimulation process that can impact frac connectivity, conductivity and ultimately, their production. This presentation illustrates recent observations about Perforation Cluster Efficiency (PCE) using FO diagnostics and summarizes the results for many wells with Cemented Plug and Perforated completions Limited Entry design (CPnP LE).