The water recovered from hydraulic-fracturing operations (i.e., flowback water) is highly saline, and can be analyzed for reservoir characterization. Past studies measured ion-concentration data during imbibition experiments to explain the production of saline flowback water. However, the reported laboratory data of ion concentration are approximately three orders of magnitude lower than those reported in the field. It has been hypothesized that the significant surface area created by hydraulic-fracturing operations is one of the primary reasons for the highly saline flowback water.
In this study, we investigate shale/water interactions by measuring the mass of total ion produced (TIP) during water-imbibition experiments. We conduct two sets of imbibition experiments at low-temperature/low-pressure (LT/LP) and high-temperature and high-pressure (HT/HP) conditions. We study the effects of rock surface area (As), temperature, and pressure on TIP during imbibition experiments. Laboratory results indicate that pressure does not have a significant effect on TIP, whereas increasing As and temperature both increase TIP. We use the flowback-chemical data and the laboratory data of ion concentration to estimate the fracture surface area (Af) for two wells completed in the Horn River Basin (HRB), Canada. For both wells, the estimated Af values from LT/LP and HT/HP test results have similar orders of magnitude (approximately 5.0×106 m2) compared with those calculated from production and flowback rate-transient analysis (RTA) (approximately 106 m2). The proposed scaleup procedure can be used as an alternative approach for a quick estimation of Af using early-flowback chemical data.
However, successful hydraulic stimulation treatments can be challenging to implement, and require considerable forethought. Compositional variation, rock fabric, geomechanical stratigraphy, and natural fracture systems all interact to influence and complicate hydraulic fracture treatments in shale reservoirs (Gale et al., 2006; Passey et al., 2010). Previously published work has highlighted the interaction between natural and induced fractures in the Horn River Basin (Dunphy and Campagna, 2011). This indicates that effective well completions require the efficient utilization of natural fracture systems to enhance permeability and drainage volume. Since natural fracture systems are a significant factor controlling the response of shale reservoirs to hydraulic fracturing, it is essential to identify and understand the key parameters of natural fracture networks that influence the effectiveness of hydraulic fracturing treatments. This paper combines results from natural fracture network characterization with discrete fracture network (DFN) modelling to identify the key parameters that influence hydraulic fracture geometry in the Horn River Basin.
ABSTRACT: Fractures play an essential role in many unconventional reservoirs, yet our ability to see and characterize them is often limited. It is common to observe few vertical fractures in vertical image logs and many in horizontal or inclined well images. Core gives the highest resolution and the best characterization but has limited application because of the time and cost involved. Image logs are acquired more frequently and can be obtained from wells of all orientations and over long intervals. After de-biasing and comparing fracture intensities between vertical cores, vertical image logs and inclined/horizontal images there is a noticeable difference in the ability to detect/resolve fractures from the three data sources. Many fractures that are visible to the eye in core are not resolved in a wellbore image. There is clearly better visibility of fractures in the horizontal images than in the vertical images. In addition to the effect of well orientation on sampled fracture density, the effects of image coverage, obscuring features and altered stress at the wellbore wall influence the visibility of fractures. This paper examines these effects and compares the observed fracture abundance to a minimum size-intensity relationship derived from core observations.
ABSTRACT: This paper summarizes our experience using two hydraulic fracture simulators that include DFN models of natural fractures that have been well characterized.
For a well pad within the Horn River basin, a 3D DFN model was built using scaled core and image log characterization of the natural fractures. Fracture properties and hydraulic fracturing parameters were adjusted to provide a match to the microseismic event distributions observed in the field. This simulator induces a hydraulic fracture at each entry point and then balances the growth of that fracture and the invasion of natural fractures by considering the hydraulic, orientation and connection properties of the natural fractures.
A second simulation of hydraulic fracturing was performed in a propagation simulator that uses a 2D DFN model that is extended vertically across all the reservoir zones. This simulator uses natural fractures strictly as mechanical weaknesses in the rock. The effect of natural fractures on the propagating fractures is determined by a crossing rule. Stress shadowing both between fracturing stages and wells was also utilized to both increase complexity and to modify height growth.
The 3D DFN fracture hydraulic model produced highly complex stimulated fracture networks whereas the 2D DFN based propagation model produced a less complex stimulation. Both models developed inter-zonal connections that could explain the hydraulic fracturing pressure hits and production interference observed between wells in the field. A key factor impacting stimulated reservoir width in both models is the variation in primary natural fracture orientations.
Ueda, Kenji (INPEX Corporation) | Kuroda, Shintaro (INPEX Corporation) | Rodriguez-Herrera, Adrian (Schlumberger) | Garcia-Teijeiro, Xavier (Schlumberger) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio J. J. (Nexen Energy ULC) | Tokunaga, Hiroyuki (INPEX Corporation) | Makimura, Dai (Schlumberger) | Lehmann, Jurgen (Nexen Energy ULC) | Petr, Christopher (Nexen Energy ULC) | Tsusaka, Kimikazu (INPEX Corporation) | Shimamoto, Tatsuo (INPEX Corporation)
A design of hydraulic fracturing in variably-stressed zones is one of key components for an effective multi-zone, multi-horizontal well pad treatment. In the recent literature, optimum completion strategies catering for stimulation-induced in-situ stress changes are discussed, however, only few of these focus on vertical stress changes and its impact on multi-zone fracture geometries. In this paper, we present an approach to design contained hydraulic fractures in a high stress layers by studying the role of vertical stress shadowing on actual field data.
In modeling hydraulic fractures with pseudo-3D models, if fracture simulations are initiated in high stress zones, "artificially" unbounded height growth results in very limited lateral propagation. On the other hand, 3D hydraulic fracturing models are too computationally expensive to optimize large design jobs, for example, in multi-horizontal well pads. In this paper, we employ a Stacked Height Growth Model, whereby fractures are also discretized vertically yet retain the numerical formulation pseudo-3D models. Coupling with finite element stress solvers then allows to identify vertical stress changes in the vicinity of induced hydraulic fractures and to understand the interference between hydraulic fracture sequences and their respective microseismic signatures.
Considering a potential combination of fracturing sequences, it was revealed that stress perturbations from the neighboring well hydraulic fractures initiating from low stress layers can be used to increase stress within the same zone and also potentially reduce stresses in higher-stress layers above and below. By modeling and calibrating an actual multi-zone, multi-horizontal stimulation job, we elaborate on the benefits of increasing stress barriers before fracturing in higher-stress layer to avoid the chances of re-fracturing from high stress zones. Regarding hydraulic fracture geometries, we explain our results by analyzing actual microseismic observations with respect to simulated stress patterns after stimulation. We explore the notion of deliberately ordering hydraulic fracture to manage vertical interference and create more contained fractures in a multi-zone horizontal well pad.
Fracturing in a higher-stress zone will naturally divert the energy into low stress, potentially unproductive zones. In an effort to manage this phenomenon, this paper presents one of the few data-rich case studies on multi-zone, multi-well engineered stimulation design. The approach shown in this paper can be a helpful reference to understand fracture height growth in the presence of both vertical and horizontal stress shadowing.
This study presents a workflow for identifying and evaluating well interference, and investigating how interference affects fracture cleanup in a multi-well pad.
We analyze flowback pressure and tracer data from a 10-well pad completed in three shale members of the Horn River Basin. Three key steps are used in this study: First, we analyze the tracer concentration profiles to investigate well interference in the pad before flowback. Second, we compare the casing pressure of the wells during selective shut-in and re-opening to investigate well interference during flowback and post-flowback periods. Third, we construct diagnostic plots of gas-water ratio (GWR) to see how well interference affects fracture cleanup during flowback.
We observe that well interference in the pad occurs in three stages – before flowback, during flowback and during post-flowback. Before flowback, concentration profiles from some wells show early breakthrough of tracers injected into neighboring wells in the pad. Analysis of the tracer data suggests that fracturing operations create connecting pathways among the wells in the pad. During flowback and post-flowback, we observe that the shut-in and re-opening of some wells in the pad disturb the recorded pressure in the remaining wells. The log-log plots of GWR versus cumulative gas production for late-opened wells show an approximate half-slope, suggesting fracture cleanup. However, this trend of fracture cleanup is not observed for the early-opened wells. This shows that the early-opened wells drain fracturing water from the late-opened wells through connected fractures, when the wells in a pad are opened for flowback in a sequence. Combined analysis of flowback and tracer data helps to understand how fracturing water migrates between wells, and to optimize well placement in a pad.
“Frac-hit” is a common phenomenon when multi-fractured horizontal wells are tightly spaced in an unconventional reservoir. Frac-hit is a rapid pressure increase in wells that are shut-in during the fracturing treatment of offset wells. Well interference during fracturing operations has been identified and evaluated using the pressure increase during frac-hit (Sardinha et al. 2014; Lehmann et al. 2016). However, it is not clear if the well interference caused by frac-hit is sustained after fracturing treatment, and how it affects hydrocarbon production.
Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions. In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin.
Zolfaghari, Ashkan (University of Alberta) | Tang, Yingzhe (University of Alberta) | He, Jia (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio (Nexen Energy ULC)
As observed in many shale-gas plays, the produced flowback water is highly saline and the salt concentration increases with time. Several past studies investigated water-rock interactions to interpret flowback chemical data, evaluate reservoir performance, and investigate the environmental impacts of fracturing operations. In this study, we measure the total ion produced (
In order to investigate the effect of
Zhou, Zhou (China University of Petroleum Beijing) | Hoffman, Todd (Montana Tech) | Bearinger, Doug (Nexen Energy ULC) | Li, Xiaopeng (Colorado School of Mines) | Abass, Hazim (Colorado School of Mines)
After hydraulic fracturing, only 10 to 50% of the fracturing fluids is typically recovered. This paper investigates how the remaining fracturing fluids are imbibed by shale as a function of time, and it investigates the influence of various parameters on the imbibition process that include lithology, reservoir characteristics, and fluid properties. In addition, on the basis of experimental results, a numerical model has been developed to estimate the volume and rate of spontaneous imbibition over the entire fracture face. The rock samples are from the Horn River formation onshore Canada. The fracturing fluids used in the experiments included 2% KCl, 0.07% friction reducer, and 2% KCl substitute. In the experimental control group, distilled water was used. Through spontaneous- imbibition experiments, the relationship between imbibed fluid volume and time indicated that clay content was the most important factor that affected the total imbibed amount. Shale matrix with high clay content could imbibe more fracturing fluids than its measured porous space because of the clay’s strong ability to expand and hold water. According to contact-angle-test results, the strongly water-wet shale samples had a faster imbibed rate. Total organic carbon (TOC) and porosity had no influence on imbibed volume and rate. These experimental findings can contribute to an improved fracturing-fluid design for different shale-formation conditions to reduce fluid loss. The experiment showed that 2% KCl and 2% KCl substitute fracturing fluids were imbibed from 10 to 40% less than 0.07% friction reducer in the shale formation with high clay content, whereas in the shale formation with low clay content, the opposite occurred. In the low-clay-content shale, 0.07%-friction reducer test fluid was imbibed from 10 to 30% less than 2% KCl fluid, but had an imbibed amount similar to that of 2% KCl substitute fluid. The numerical-model result was matched with the experimental result to estimate a relative permeability in the model that could represent the rock properties. This model could be used to estimate the total imbibed volume along fracture faces through spontaneous imbibition.
As observed in many shale-gas operations, salt concentration of flowback water increases with time. Usually, the shape of salt-concentration/load-recovery plots is different from one well to another. We hypothesize that the shape of the salinity profile during the flowback process provides useful information about the complexity of the fracture network. In this study, we propose a model to describe the relationship between salinity and cumulative water production. We also compare the model results and flowback-salinity data to characterize the fracture network.
Flowback-salinity data are collected from three multifractured horizontal wells completed in the three shale members [Muskwa (Mu), Otter-Park (OP), and Evie (Ev)] of the Horn River Basin. The salinity profiles for the Mu and OP wells initially increase and finally reach a plateau, whereas the salinity profile for the Ev well shows a continuous increase and does not show a plateau. We hypothesize that the early water with lower salt concentration at the onset of the flowback process is mainly produced from the primary fractures with larger aperture size. Also, we believe that the fractures with smaller aperture size become more important as the flowback process progresses, and therefore, the high-salinity water produced at later times is mainly produced from secondary fractures. We also propose a model to describe the salinity-profile behaviors. The model presents the aperture-size distribution (ASD) of the fracture network. A comparative analysis of the model results and the flowback-salinity data indicates that the Ev well with a steady increase in its salinity profile has a wider ASD compared with the Mu and OP wells with a plateau in their salinity profiles. This suggests that the fracture network is more complex in Ev compared with those in Mu and OP. More-complex fracture network in Ev is also in agreement with its higher gas and lower water recovery during the flowback process as opposed to the lower gas and higher water recovery in Mu and OP.
The presented model for describing the behavior of the salinity profile during the flowback process and its meaningful relationship to the fracture-network complexity provide an alternative approach for reservoir characterization. This study encourages the industry to manage the flowback operations carefully and to monitor the water chemistry.