The optimization of well spacing has become more important in unconventional shale reservoirs to efficiently design infill developments, estimate the Stimulated Reservoir Volume (SRV), and more importantly the estimation of Ultimate Oil Recovery (EUR) from each well. This paper presents a new analytical solution to estimate the start and end of pseudo-transient flow for the data production analysis where boundary-dominated flow exists in the induced fractures hence estimate the SRV for hydraulically fractured horizontal wells for unconventional shale reservoirs.
This paper presents a semi-analytical model to obtain the pressure transient response to characterize the flow and estimate the boundary effect which can be used to analyze the field data in unconventional shale reservoirs. The results from the model are compared and validated against an in-house developed numerical simulation model. The semi-analytical model is based on trilinear model where the SRV is modeled using dual-porosity idealization. The developed model involves the simulation of interference tests for two hydraulically-fractured horizontal well in unconventional shale reservoir using the real-time distributed pressure data. The proposed asymptotic solution evaluates not only the pseudo-transient in induced fractures but also the matrix.
The pressure measurements from real-time distributed pressure sensors and the production measurement using interference test provide a better understanding of the physical phenomena of the interaction between the parent and child wells in shale reservoirs. This paper presents a new model to assess the interference characteristics in horizontal wells to evaluate the optimum well spacing in unconventional shale reservoirs. It is observed that the production from a well is greatly affected by the distance of the wells, the reservoir properties between the wells, and the matrix permeability. It is presented that if the matrix permeability is lower, the start of the pseudo transient flow is sooner; therefore, the drainage volume becomes smaller. This can be observed by comparing the field data from unconventional shale reservoirs in Bakken and Eagle Ford where the matrix permeability in Bakken is higher than that of the Eagle Ford; therefore, the wells observe longer linear flow regime in higher permeability with larger SRV and in-turn larger well-spacing. The proposed asymptotic solution can also be used to analyze the field data in unconventional shale reservoirs to decipher the productivity and economics of horizontal wells.
To effectively produce from unconventional shale reservoirs, an optimum well spacing is required. This paper presents a novel asymptotic solution to characterize the flow regimes and provide a novel formulation in analyzing the pressure and rate variation with time to forecast future performance.
Banack, Ben (Halliburton) | Burke, Lyle H. (Devon Canada Corporation) | Booy, Daniel (C-FER Technologies 1999 Inc.) | Chineme, Emeka (Cenovus Energy) | Lastiwka, Marty (Suncor Energy) | Gaviria, Fernando (Suncor Energy) | Ortiz, Julian D. (ConocoPhillips Canada) | Sanmiguel, Javier (Devon Canada Corporation) | Dewji, Ayshnoor (Halliburton)
It is becoming common to install inflow control devices (ICDs) along steam-assisted gravity drainage (SAGD) production liners to enhance temperature conformance and accelerate depletion. Additionally, some operators advocate the installation of similar outflow control devices (OCDs) along the injection well of the SAGD well pair. Collectively, these inflow and outflow devices are often referred to as FCDs. Industry adoption of flow control devices (FCDs) has increased, and several devices are commercially available for use in SAGD.
In an effort to optimize FCD design and selection, a joint industry partnership (JIP) was formed (
Fiber-optic-based instrumentation was deployed within FCD-equipped wells using permanently installed coiled tubing. Well architecture design changes to a typical completion were not required because fiber-optic sensors are used for most non-FCD wells to collect distributed temperature sensing (DTS) data. Although DTS is a common tool for optimizing SAGD production, it has certain limitations; specifically, temperature changes along production wells do not typically allow a detailed definition or quantification of the inflow distribution along the wellbore.
In addition to DTS, distributed acoustic sensing (DAS) was periodically performed on the FCD wells. DAS logging of SAGD producers has several potential uses, including flow profiling, steam breakthrough and/or noncondensable gas (NCG) detection, multiphase flow characterization, electric submersible pump (ESP) performance, completion failure analysis, and four-dimensional seismic analysis. Although FCD characterization with DAS appears promising, a knowledge gap exists as to how to move beyond qualitative analysis to more quantitative analysis of FCD performance and the lateral emulsion inflow distribution. Pending satisfactory results, DAS logging on active wells can potentially be completed to accelerate improvements of SAGD FCD performance and design as well as increase the efficiency of SAGD recovery through improved steam/oil ratio (SOR) and an associated reduction in greenhouse gases.
This paper describes piloting the collection and analysis of DTS and DAS data to help improve understanding of SAGD inflow distribution. Logs were performed on multiple wells during stable and transient flowing conditions. Early surveillance demonstrated suitability and limitations of fiber-optic-based logging to validate FCD performance in active wells. In addition to field logging, acoustic recording using JIP flow loop testing was completed with accelerometers, geophones, and fiber-optic cables during FCD characterization. The goal was to cross reference the acquired acoustic signals for quantification of flow at devices and validation of performance. An overview of the JIP flow loop FCD acoustic characterization program is described.
Fiber optic technology has been used in several wells at an oilfield to measure strain to monitor overburden deformation. The application of this technology involved a series of bench tests and field tests to gather some key learnings to enhance well design, well construction, and fiber optic operation. Prior to installation of the fiber optic, a series of bench tests were conducted to evaluate the coupling of fiber with the capillary lines to determine its impact on the measurement of strain. The testing demonstrated that anchoring the fiber at the top and bottom of the capillary line was sufficient to hold the fiber in place and enabled the effective measurement of strain along the length of the well, which was proven when applied to field conditions. To enhance well design for strain measurement, several wells had fiber optic capillary lines installed on the inside and outside of casing to investigate the potential dampening effect due to fiber being located inside a string of casing. This was used to determine the optimal casing string to install fiber optic to measure strain in the overburden. Additionally, a novel concept was utilized in the well design that involved using the fiber optic capillary clamps as borehole centralizers, which resulted in equipment and rig cost savings. The details of the bench tests, well design, operational experience, and their associated lessons learned are presented.
The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest.
There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells.
A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility.
The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions.
Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements.
The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased.
A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed.
The reduction of HSE risks through a better management of field operators is also assessed.
An optical fiber has been utilized to continuously acquire liquid production profiles in horizontal well in X oilfield. The results obtained from the dynamical monitoring system confirm the time-varying law of the physical property under the condition of high-water flooding, which can serve as the guidelines to explore the potential of remaining oil in high water-cut/high recovery factor oilfield.
Usually, the sound wave shows different propagation speeds in different medium, which is the basic principle of this test. Firstly, optical cable is used for sound wave detection and signal demodulation.Meanwhile, a series of other processes are applied to calculate the sound velocity of mixed medium; Then the volume velocity and holdup of mixed medium for each phase are determined.The measure of liquid-producing profile along the whole horizontal well has been realized in real time. Finally, numerical simulation model considering the time-varying physical properties is established based on the core flooding laboratory experiment. This result will provide guidelines for the exploration of remaining oil in the well.
The results obtained from optical fiber monitoring system during last two years show that 80% of the fluid produced from the 502-meter horizontal well is mainly contributed to the first 90-meter horizontal section. Experimental results of core flooding under excessive water flooding (2000 pore volume) indicate that the permeability is 1.4 times of the original. The results of numerical simulations considering the time-varying physical properties illustrate that there is still internal remaining oil along the horizontal well section. So, the strategy of exploiting potential oil is proposed using an accurate directional water plugging, which will decrease 10% water cut and obtain more recoverable reserves.
Based on the dynamical monitoring results of optical fiber, this paper innovatively provides the strategy of exploiting potential remaining oil in the horizontal wells, which can provide a valuable suggestion for offshore oilfield with high productivity at high water-cut stage.
Hydraulic fracturing stimulation designs are moving towards tighter spaced clusters, longer stage length, and more proppant volumes. However, effectively evaluating the hydraulic fracturing stimulation efficiency remains a challenge. Distributed fiber optic sensing, which includes Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS), can continuously monitor the hydraulic fracturing stimulation downhole and be compared with other monitoring technology such as microseismic. The DAS and DTS data, when integrated with the microseismic, highlight processes relevant to the completion design and allow for a better understanding and interpretation of each dataset.
This paper outlines a workflow to improve processing and interpretation of DAS and DTS data. In addition, an estimate of the slurry distribution can be made. These methods will be demonstrated for a horizontal Wolfcamp well in the Permian Basin. Here we compare key aspects of the microseismic, DAS, and DTS results in several fracture stages to understand the downhole geomechanical processes. In order to interpret the DTS data a thermal model is developed (using DTS data) to simulate the temperature behavior after pumping has ceased. A slurry distribution is obtained by matching the simulated temperature with the measured temperature from DTS. In addition, the DAS data signal is studied in the frequency domain and the dominant frequencies are identified that are mostly related to fluid flow and to reduce the background noise. This time frequency analysis enhances the ability to monitor and optimize well treatments.
After reducing the background noise, the acoustic intensity is correlated to the slurry distribution. The fluid distribution data from DAS and DTS are compared with the microseismic and near field strain to better understand the completion processes. We utilized fiber optic microseismic to better understand and compare it to conventional microseismic.
Finally, we highlight the dynamics of strain and microseismic signature as fluid moves from an offset well completion into the prior stimulated fiber well to better understand the reservoir and far field effects of the completion.
Binder, Gary (Colorado School of Mines) | Titov, Aleksei (Colorado School of Mines) | Tamayo, Diana (Colorado School of Mines) | Simmons, James (Colorado School of Mines) | Tura, Ali (Colorado School of Mines) | Byerley, Grant (Apache Corporation) | Monk, David (Apache Corporation)
In 2017, distributed acoustic sensing (DAS) technology was deployed in a horizontal well to conduct a time-lapse vertical seismic profiling (VSP) survey before and after each of 78 hydraulic fracturing stages. The goal of the survey was to more continuously monitor the evolution of stimulated rock throughout the treatment of the well. From two vibroseis source locations at the surface, time shifts of P-waves were observed along the well that decayed almost completely by the end of the treatment. A shadowing effect in the time shifts was observed that enables the height of the stimulated rock volume to be estimated. Using full wavefield modeling, the distribution of time shifts is well described by an equivalent medium model of vertical fractures that close as pressure declines due to fluid leak-off. Converted P to S waves were also observed to scatter off stimulated rock near some stages as confirmed with full wavefield modeling. The signal-to-noise ratio is a limitation of the current dataset, but recent improvements in DAS technology can enable stage-by-stage monitoring of the stimulated rock height, fracture compliance, and decay time as a well is completed.
Distributed Acoustic Sensing (DAS) has opened new possibilities for seismic monitoring of unconventional reservoirs. Using a laser interrogator to launch light pulses down a fiber optic cable, dynamic strain changes can be sampled along the cable from the phase shift of light backscattered to the interrogator (Hartog, 2017). Since the fiber optic cable can be permanently cemented outside the casing in a borehole, highly repeatable vertical seismic profiling (VSP) surveys can be acquired frequently without costly wireline geophone deployments that interfere with well treatment activities (Mateeva et al., 2017; Meek et al., 2017).
As described by Byerley et al., 2018, a unique interstage DAS VSP survey was conducted in 2017 during the stimulation of a horizontal well targeting the Wolfcamp formation in the Midland Basin, Texas. Using two vibroseis source locations offset about 1 mile from the heel and toe of the well, DAS data was acquired in the treatment well before and after each of 78 hydraulic fracturing stages. At the expense of fewer source locations, this type of acquisition allows the evolution of the stimulated rock volume (SRV) to be monitored on a stage-by-stage basis as the well is treated.
Carr, Timothy (West Virginia University) | Ghahfarokhi, Payam (West Virginia University) | Carney, BJ (Northeast Natural Energy, LLC) | Hewitt, Jay (West Virginia University) | Vargnetti, Robert (USDOE National Energy Technology Laboratory)
The Marcellus Shale Energy and Environment Laboratory (MSEEL) involves a multidisciplinary and multi-institutional team of universities companies and government research labs undertaking geologic and geomechanical evaluation, integrated completion and production monitoring, and testing completion approaches. MSEEL consists of two legacy horizontal production wells, two new logged and instrumented horizontal production wells, a cored vertical pilot bore-hole, a microseismic observation well, and surface geophysical and environmental monitoring stations. The extremely large and diverse (multiple terabyte) datasets required a custom software system for analysis and display of fiber-optic distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) data that was subsequently integrated with microseismic data, core data and logs from the pilot holes and laterals. Comprehensive geomechanical and image log data integrated with the fiber-optic data across individual stages and clusters contributed to an improved understanding of the effect of stage spacing and cluster density practices across the heterogeneous unconventional reservoirs such as the Marcellus. The results significantly improved stimulation effectiveness and optimized recovery efficiency. The microseismic and fiber-optic data obtained during the hydraulic fracture simulations and subsequent DTS data acquired during production served as constraining parameters to evaluate stage and cluster efficiency on the MIP-3H and MIP-5H wells. Deformation effects related to preexisting fractures and small faults are a significant component to improve understanding of completion quality differences between stages and clusters. The distribution of this deformation and cross-flow between stages as shown by the DAS and DTS fiber-optic data during stimulation demonstrates the differences in completion efficiency among stages. The initial and evolving production efficiency over the last several years of various stages is illustrated through ongoing processing of continuous DTS. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Engineered stages that incorporate the distribution of fracture swarms and geomechanical properties had better completion and more importantly production efficiencies. We are working to improve the modeling to understand movement within individual fracture swarms and history match at the individual stage. As part of an additional MSEEL well pad underway incorporates advanced and cost-effective technology that can provide the necessary data to improve engineering of stage and cluster design, pumping treatments and optimum spacing between laterals, and imaging of the stimulated reservoir volume in the Marcellus and other shale reservoirs.
Mondal, Somnath (Shell International Exploration and Production) | Ugueto, Gustavo (Shell Exploration and Production Company) | Huckabee, Paul (Shell Exploration and Production Company) | Wojtaszek, Magdalena (Shell Global Solutions International) | Daredia, Talib (Shell Canada Limited) | Vitthal, Sanjay (Shell Exploration and Production Company) | Nasse, David (Shell Exploration and Production Company) | Todea, Felix (Shell Canada Limited)
In recent years, Step-Down Tests (SDTs) are being increasingly used for diagnosing completions effectiveness in plug-and-perf (PnP) fracturing in unconventional wells. SDT is primarily used to quantify pressure drop related to perforation friction, near-wellbore tortuosity (NWBT), and to estimate perforation efficiency (PE) i.e. the fraction of active perforations at the end of a hydraulic fracturing treatment of a stage. In the industry, perforation efficiency is generally considered to be the yardstick for evolving limited entry designs and perforating strategies. In a typical SDT, the injection flowrate is reduced in 3 to 4 abrupt steps, each of duration long enough for the rate and pressure to stabilize, to enable interpretation of the rate and pressure response. However, simple as it may appear to be, the interpretation of SDT as a stand-alone diagnostic test has several assumptions and inherent non-uniqueness that are often ignored. This paper presents integrated data, diagnostics, and analysis from multiple completion types across multiple basins that demonstrates the methodology and uncertainties associated with SDT analysis.
In this paper, the SDT methodology was applied to 2 wells with different completion styles, and the interpretation was supplemented with fiber optics and bottomhole pressure gauges (BHPG). In the first well, SDTs were conducted on multiple stages of a cemented single-point entry (CSPE) sleeve completion that had well-defined, erosion-resistant openings to reduce uncertainties in the “perforation” pressure drop solution. In the second example, SDTs were conducted on multiple stages of a PnP well. Each PnP stage had two SDTs – one was conducted post pad but before proppant and another at the end of entire treatment, both with clean fluids.
The authors have highlighted the uncertainties with traditional SDTs and the need for integration with additional diagnostics. The analysis shows that the exponent of flowrate commonly used to quantify pressure drop associated with NWBT is largely uncertain. It also demonstrates the non-uniqueness of the SDT interpretation, and that a range of perforation diameters and a / the number of active perforations can match the SDT unless constrained with fiber optics data and perforation imaging data. The interpretation with constant perforation diameter is found to generally overestimate the PE. The SDTs before and after proppant slurry placement, if correctly interpreted, show an increase in perforation diameter with a reduction in PE post proppant placement. This paper demonstrates that without constraints on either eroded perforation diameter or on a / the number of active perforations, the interpretation of SDT is non-unique.
Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) analysis also illustrates the variable and non-unique tortuosity, and/or complex stimulation domain architecture, in the near-wellbore region. It is therefore recommended that SDTs be interpreted with consideration of the inherent complexities and uncertainties, and preferably supplemented either with perforation imaging or DAS and DTS data for more accurate analysis.
To summarize, accurate interpretation of SDTs requires an interdisciplinary diagnostics approach, which is critical for optimization of limited entry designs.
Acid fracture operations in carbonate formations are used to create highly conductive channels from the reservoir to the wellbore. Conductivity in calcite formations is expected to be highest near the wellbore, where most of the etching occurs. The near wellbore fracture etched-width profile can be estimated from the measured temperature distribution. Temperature data can be obtained from fiber optic distributed temperature sensing (DTS) installed behind casings to monitor fracturing operations.
Heat transfer is commonly coupled in acid fracture models to account for temperature's effects on acid reactivity with carbonate minerals. Temperature profiles are usually evaluated during simulations of fracture fluid injection, but seldom during fracture closure. Since most of the acid is spent during injection, many models have assumed that the remaining acid reacts proportionally along the fracture length. Because of this assumption, neither acid spending nor temperature is usually simulated during fracture closure.
In this study, a fully integrated temperature model was developed wherein both the acid reaction and heat transfer were simulated while the fracture was closing. At each time step, transient heat convection, conduction, and generation were calculated along the wellbore, reservoir, and fracture dimensions. Modeling temperature during this transient period provides a significant understanding of the fracture etched-width distribution. During shut-in, cold fracture fluids are heated, mainly because of heat flow from the formation to the fracture. The amount of fluid stored in the fracture determines how fast the fluid is heated. Wider fracture segments contain larger amounts of cold fracture fluids, resulting in it taking longer to reach the reservoir temperature. Because of this phenomenon, near a wellbore, the vertical fracture etched-width profile can be determined from the temperature distribution. Also, minerals' spatial distributions along the wellbore's lateral can be estimated in multistage acid fracturing. This is done by minimizing the difference between the observed and modeled temperatures.
This evaluation of etched width profiles at the fracture entrance provides an estimation of fracture-conductive channel locations. Moreover, it has significantly improved the understanding of mineralogy distribution in multi-layer formations. This information will be particularly useful when designing acid fracturing jobs in nearby wells or revisiting the same wellbore for further stimulation.