Combination Of Horizontal Wells Research Articles

Fiber-Optics Approach Monitors Drainage Profile of Multistage Stimulation

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212364, “Can You Feel the Pressure? Strain-Based Pressure Estimates,” by Kyle Haustveit, SPE, and Jackson Haffener, SPE, Devon Energy. The paper has not been peer reviewed. _ The combination of horizontal wells and hydraulic stimulation has been key in unlocking vast unconventional resources across North America and elsewhere, but much remains to be understood regarding how the reservoir is drained across the miles of laterals accessing a resource. The density of pressure gauges required to accurately measure the drainage pattern from a horizontal multistage stimulation is currently not realistic economically or technologically. In this case study, the authors describe a method of monitoring the drainage profile of a horizontal multistage stimulation using optical fiber. Introduction An advanced subsurface diagnostic project was deployed as part of the Hydraulic Fracture Test Site I, Phase 3, funded by the Department of Energy. A lateral observation well was positioned approximately 225 ft away from the nearest two stimulated and producing horizontal wells. Using optical fiber and Raleigh frequency-shift distributed strain sensing (RFS-DSS), strain change was measured in the far field as the offset well was stimulated and first produced. RFS-DSS provides a spatial resolution of 20 cm, allowing for the monitoring of strain changes at finer spatial resolution than can be sensed accurately with low-frequency distributed acoustic sensing. The strain change during the interference test correlated with both the strain change during the crosswell refracturing monitoring and the pressure-gauge change along the monitor well during the interference test. The strong correlation between crosswell refracturing and interference strain monitoring suggests that the magnitude of crosswell strain responses is directly proportional to the intensity of strain change when the offsetting wells are put online. The comparison of data recorded from RFS-DSS and six reservoir-sensing pressure gauges displayed a strong correlation between the total strain change and total pressure drawdown. Three gauges positioned in regions of large negative strain change during first production, interpreted as drawdown, showed large pressure declines; the other three gauges, positioned in areas of small strain change, saw small pressure declines. The correlation was applied to the total length of the wellbore based on the strain change to estimate a pressure along the entire lateral, including areas without pressure gauges. Pilot Design Located in DeWitt County, Texas, the project consisted of a combination of production infill wells (12H and 13H), pre-existing primary wells (2H, 4H, 6H, and 8H), liner refracturing wells (3H and 5H) and one unstimulated observation well (14H). The wells are landed in the lower Eagle Ford formation. While drilling the observation lateral, horizontal core was collected and used to investigate the frequency of hydraulic and propped fractures created from the 4H and 5H original stimulations. The 14H lateral was equipped with permanent optical fiber, one internal pressure-sensing gauge used for sealed wellbore pressure monitoring, and nine reservoir-sensing pressure gauges to monitor fracture interactions and pressure drawdown from the offset wells. Three of the gauges failed to show connection to the reservoir and were discarded for this analysis.

Effects of cyclic cryogenic treatment on rock physical and mechanical properties of Eagle Ford shale samples - An experimental study

Unconventional reservoirs have ultra-low permeability, and the combination of horizontal wells and multistage transverse hydraulic fracturing have unlocked economical hydrocarbon production from such formations. Fracturing fluid involves large volumes of water that is partially recovered during the flowback stage, and the rest remains in the formation damaging the matrix-fracture interface. In this paper, an alternative waterless stimulation technique has been studied. A cryogenic fluid, liquid nitrogen (LN2), was injected into cores from Eagle Ford formation. The effects of cyclic LN2 on rock physical and dynamic elastic properties were examined. Two cycles of injecting LN2 into cores at the reservoir temperature and pressurizing at different pressures (1.38, 2.76, 4.14 MPa) were implemented. Before and after each cycle, computerized tomography scan, porosity, permeability, and ultrasonic velocities tests were conducted on the samples. The results demonstrated that cyclic cryogenic treatment increases porosity and permeability and decreases ultrasonic velocities of the samples resulting from inducing new cracks and extending and widening the existing ones. Permeability enhancement, which results from the creation of high-permeable pathways allowing the gas to move rapidly across the tested samples, was noticeable (up to 2 orders of magnitude). Whilst, comparing to permeability, the porosity improvement was not significant (up to 26%) owing to the small increase in pore volume compared to the sample's bulk volume. The results showed a direct relationship between injection pressure and porosity and permeability enhancements after the completion of each cycle. Moreover, the reductions in ultrasonic velocities and dynamic elastic properties were insignificant compared to the changes in the porosity and permeability. Additionally, porosity and permeability enhancements and velocities reduction mainly occurred after completing the first cycle. This is because of lowering the thermal stress on samples, which results in reducing the possibility of creating new cracks or propagating and widening the current ones.

Guest Editorial: Growth in Unconventional Resources Adds to Technical Literature

Guest editorial Unconventional resources require technologies typically not used to produce conventional oil and gas reservoirs. In particular, starting in the late 1990s, the combination of horizontal wells and multistage hydraulic fracturing has been key to rapidly increasing success in exploiting unconventional resources. While the well completions in unconventional resources may be more expensive than those typically applied in conventional reservoirs, the advantage is access to the very large volumes of these resources, which include tight (low-permeability) gas in sandstone or carbonate rock, coalbed methane, and organic-rich source rocks classed as shale gas and tight oil. The exploitation of shale gas, along with tight gas and coalbed methane, enabled a stunning increase in US natural gas production of approximately 4 Tcf/D from 2005 to 2010. A similar story followed a few years later for US crude oil production. Tight oil production ramped up nearly 5 million B/D over approximately 5 years, starting in 2008, and continues to rise. And it is not just the US that is benefiting—unconventional resource development is now beginning to spread to other countries around the world. The technologies that accomplished these near miracles were developed, implemented, and continue to be improved largely by SPE members, and this has been reflected in an upsurge in conference presentations and journal publications related to unconventional resources over the past decade. This is illustrated by the chart (Fig. 1), which shows a dramatic increase in the percentage of peer-reviewed papers related to unconventional resources published in SPE Reservoir Evaluation & Engineering (SPEREE) beginning in 2011. Before 2011, there were only a handful of publications related to unconventional resources each year, primarily dealing with coal-bed methane and fundamentals of fluid flow in tight pore systems. Beginning in 2011, publications related to the analysis and prediction of shale gas reservoir production performance showed a sharp increase, followed a few years later by publications related to tight oil reservoir performance analysis and prediction. In addition, enhanced oil recovery from tight oil reservoirs has become an increasing area of focus. This year, over half of the publications in SPEREE will be related to unconventional resources. As further indication of the increasing importance of unconventional resources, in July SPE released Unconventional Gas and Tight Oil Exploitation, the first SPE monograph devoted exclusively to the topic.

Modeling tracer flowback in tight oil reservoirs with complex fracture networks

Tight oil reservoirs are commonly developed by a combination of horizontal wells and multistage hydraulic fracturing techniques. The characterization of complex fracture networks after fracturing treatments is a common challenge for unconventional reservoirs. Tracer flowback profiles can reveal a fracture network at an individual stage. However, the numerical simulation of tracer transport in fractured reservoirs usually employs a dual-porosity continuum medium model or describes fractures by an enlarged fracture aperture in a regular grid system that is not capable of modeling a complex fracture network. Especially, the influences of the properties of fracturing fluid and variations in fracture permeability caused by pressure changes on tracer flowback profiles are not investigated.In this paper, a two-phase (water and oil), four-component (oil, water, fracturing fluid and tracer) numerical simulator is developed based on a discrete fracture model for modeling tracer injection and flowback in tight oil reservoirs. With respect to fracture network modeling, the simulator is capable of explicitly modeling an arbitrary distribution of fracture networks with a real fracture aperture by triangular grids. With respect to mechanism consideration, the simulator considers the influences of fracturing fluid and pressure-dependent fracture permeability on tracer flowback profiles. The properties of tracer dispersion and adsorption are also considered in both fractures and matrix. To validate the proposed model, a comparison is performed with the commercial software Eclipse. Sensitivity studies are performed to investigate the influences of parameters on tracer flowback profiles. The presented simulator is applied in the Changji oilfield to characterize individual stages using a stochastic method.Results show that the developed simulator is accurate as with Eclipse. The filed application indicates that the presented simulator can model tracer flowback and production performance. Sensitivity studies show that an increase in permeability modulus and the viscosity of fracturing fluid delays the peak arrival time. An increase in permeability modulus decreases the peak amplitude while an increase in the viscosity of the fracturing fluid increases the peak amplitude. An increase in a dead pore volume and a residual resistance factor has little impact on the peak position and lowers the tails of tracer flowback profiles. The sensitivity studies provide valuable information in characterization of a fracture network using tracer flowback data.

Investigation of a new HDR system with horizontal wells and multiple fractures using the coupled wellbore–reservoir simulator TOUGH2MP-WELL/EOS3

Geothermal energy is renewable, sustainable and available in large amounts. The hot dry rock (HDR) systems, in particular, have the largest potential for long-term sustainability and therefore draw a lot of attention. The combination of horizontal wells and the technology of multiple transverse fractures technology is an attractive approach of such HDRs, which is called in this paper as the specific EGS (enhanced geothermal system). The main objective of this paper is to study the heat extraction over a period of 20 years by water circulating in a deep geothermal reservoir using this specific EGS. The wellbore flow module, T2WELL/ECO2N, is implemented in the parallelized simulator TOUGH2MP as a new code TOUGH2MP-WELL/EOS3, which enables coupled wellbore–reservoir simulations. Using this newly developed code, the sensitivity of heat extraction against various parameters of the formation and fractures is assessed. The influences of the fracture geometry and the space of two neighborhood fractures on the geothermal energy performance are analyzed. According to the results in this paper, the injection rate, the wellbore radius and the fracture permeability are three main influence factors for the distribution of total flow through individual fractures. A large injection rate, a small wellbore radius and a large fracture width will cause the short-circuit effect, which reduces the performance of this specific EGS. Compared with the classic HDR system (doublet or triplet vertical wells + single fracture), this specific EGS has a much higher performance and a longer duration of the economic production. Furthermore, the horizontal wells can also be drilled in both directions of the minimum horizontal stress instead of in just one direction, so that the energy performance is doubled and the investment cost per kW energy production is decreased and the advantage of this specific EGS is significantly enlarged.

The Application of Horizontal and Vertical Well Patterns During Polymer Flood Processes in Anisotropic Reservoirs

Using horizontal wells in a polymer flood process, higher sweep efficiency is expected compared with the use of conventional patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate the process. This article presents an analysis of how the overall performance of a polymer flood process is influenced by the well pattern using a horizontal injector and producer in different configurations. A three-dimensional numerical model for fluid flow and mass transport is used to analyze the performance of the reservoir. The potential for a horizontal well application was assessed through different scenarios in combinations of injection and production wells and reservoir anisotropy. Results from the study have demonstrated that a significant amount of additional oil can be recovered and injectivity was remarkably improved by utilizing a combination of horizontal wells. The improvement of injectivity through a horizontal injection well was higher when it was combined with a horizontal producer parallel to the injector. The overall performances in anisotropic reservoirs strongly depend on the type of wells considered and the orientation of the horizontal wells with respect to the permeability directions. A combination of horizontal wells placed parallel to the low permeability direction yields the best performance.

Efficiency of Horizontal and Vertical Well Patterns on the Performance of Micellar-Polymer Flooding in Anisotropic Reservoirs

There is increasing interest in micellar-polymer flooding because of the need to increase oil production from depleted and waterflooded reservoirs. Using horizontal wells for injection and production in a micellar-polymer flood process, higher sweep efficiency is expected compared with the use of conventional patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate the process. This paper presents an analysis of how the overall performance of a micellar-polymer flood process in anisotropic reservoirs is influenced by the well pattern using horizontal injector and producer in different configurations. A three-dimensional numerical simulator for fluid flow and mass transport is used to analyze the effectiveness of well combinations in micellar-polymer applications. The potential for a horizontal well application was assessed through different situations in combinations of injection and production wells and degree of reservoir anisotropy. Results from the study have demonstrated that significant amount of oil can be recovered additionally and injectivity was remarkably improved by utilizing a combination of horizontal wells. The improvement of injectivity through a horizontal injection well was higher when it was combined with horizontal producer parallel to the injector. The overall performances in anisotropic reservoirs strongly depend on the type of wells considered and the orientation of the horizontal wells with respect to the permeability directions. Combination of horizontal wells placed parallel to the low permeability direction yields the best performance. In high permeability ratio reservoirs, the presence of horizontal injectors is more significant in defining the efficiency of the micellar-polymer flood than the horizontal producers. Key words: Micellar-polymer flood; Horizontal well; Anisotropy; Injectivity

Efficiency of Horizontal and Vertical Well Patterns on the Performance of Micellar-polymer Flooding

There is increasing interest in micellar-polymer flooding because of the need to increase oil production from depleted and waterflooded reservoirs. Using horizontal wells for injection and production in a micellar-polymer flood process, higher sweep efficiency is expected compared with the use of conventional patterns by vertical wells. This paper presents an analysis of how the overall performance of a micellar-polymer flood process is influenced by the well pattern using horizontal injector and producer in different configurations. Results from the study have demonstrated that significant amount of oil can be recovered additionally and injectivity was remarkably improved by utilizing a combination of horizontal wells. The improvement of injectivity through a horizontal injection well was higher when it was combined with horizontal producer parallel to the injector.

Application of Horizontal Wells to Improve Injectivity During Polymer Flood Processes

This numerical study was undertaken to investigate and compare the performances of polymer flood processes through horizontal or vertical wells. To achieve the objective, the author performed an extensive numerical simulation for 3 different well configurations under polymer flood followed by waterflood. The potential for a horizontal well application was assessed through different scenarios in combinations of injection and production wells and reservoir geometry. Other parameters included the length and spacing of horizontal injectors and horizontal or vertical producers. For different parameters of the system, performances were compared in terms of cumulative recovery and water-oil ratio at the production well and pressure drop or injectivity at the injection well. Results demonstrate that additional oil can be recovered and injectivity was significantly improved by utilizing a combination of horizontal wells when the same volume of fluid is injected into the reservoir. The improvement of injectivity through a horizontal injection well was higher when it was combined with a horizontal producer. Parameters such as reservoir thickness, well spacing, and well length are also shown to impact the predicted injectivity. Improvement in injectivity is obtained for thicker and larger reservoirs and longer horizontal wells.

Effects of Horizontal and Vertical Well Patterns during Waterflood in Anisotropic Reservoirs

ABSTRACTUsing horizontal wells in a waterflood process, higher sweep efficiency is expected compared with the use of conventional patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate the process. This paper presents an analysis of how the overall performance of a waterflood process is influenced by the well pattern using horizontal injector and producer in different configurations. The potential for a horizontal well application was assessed by numerical modeling for different scenarios in combinations of injection and production wells and reservoir anisotropy. Results from the study have demonstrated that significant amount of additional oil can be recovered and injectivity was remarkably improved by utilizing a combination of horizontal wells. The improvement of injectivity through a horizontal injection well was higher when it was combined with horizontal producer parallel to the injector. The overall performances in anisotropic reservoirs strongly depend on the type of wells considered and the orientation of the horizontal wells with respect to the permeability directions. Combination of horizontal wells placed parallel to the low permeability direction yields the best performance.