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Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.
Abstract This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are at or above the overburden gradient. Hydraulic fractures, whether created during a DFIT or a larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure. This high pressure may be caused by near well friction or tortuosity but may also be the result of more complex fractures in multiple planes. Bachman et al (2012, 2015), Hawkes et al (2018) and Nicholson et al (2019) advanced DFIT analysis by using the Pressure Transient Analysis (PTA) technique. This allows the identification of flow regimes useful for understanding fracture geometry and closure behavior beyond that available from more familiar G-function analysis techniques. In this paper DFITs from the Duvernay, Montney, Rock Creek and Cardium formations of Western Canada are analyzed using the PTA method. Particular attention is given to Early-Time Flow Regimes (ETFRs) present between the end of pump shut-down (End of Job Instantaneous Shut-In Pressure, EOJ ISIP) and the 3/2-slope Nolte flow regime. Identification of pressure gradients at the start and end of these flow regimes is of vital importance to the interpretation process. This allows the authors to build on case histories of DFIT-derived fracture geometry interpretations presented in Nicholson et al (2017, 2019). Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional IIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators. Analysis of FFEP and ETFRs combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
Pyecroft, James (Nexen Energy ULC) | Lehmann, Jurgen (Nexen Energy ULC) | Petr, Christopher (Nexen Energy ULC) | Lypkie, Kevin (Nexen Energy ULC) | Purdy, Ivan (Nexen Energy ULC) | Zafar, Hammad (Nexen Energy ULC) | Hiller, Chelsey (Nexen Energy ULC) | Meeks, David (Nexen Energy ULC)
Abstract This paper presents well construction details and pressure responses for a slant well in a dry gas shale resource in northern British Columbia, Canada. We will present the drilling and completions plan for a Multi-Stage Hydraulic Fracturing (MSHF) campaign on a ten well half pad including consequences of an aggressive fluid environment. Horn River shale gas development involves Multi-well MSHF horizontal wells from a single surface pad location. The wells are treated sequentially from toe to heel of the horizontal section, alternating between wells. Strategic placement of an Open Hole (OH) slant well equipped with slotted liner, tubing, and pressure data recorders will be presented. Pressure responses during the MSHF campaign will be presented and reviewed against calibrated closure pressure data from Diagnostic Fracture Injection Test (DFIT) data and end of job instantaneous shut-in pressures (ISIP). The initial concept of drilling an OH well placed between MSHF wells was to evaluate the fracture system between stimulated wells and to test whether an unstimulated open hole well placed between stimulated wells can economically produce gas. Other objectives were to provide an Oil Based drilling Mud (OBM) free wellbore that would enable water-based imaging logs. Water-based logs have enhanced ability to identify and map natural fractures. Initial logs would evaluate the natural fractures and subsequent post-completion logs would evaluate the hydraulic fracture transiting the shale resource rock to the OH well. Knowledge of how pre-existing natural fracture networks react to the hydraulic fracture process along with pressure response data recorded from all wells on the pad would be used to provide geoscientists and engineers the means to optimize stimulation programs for horizontal wells and wellbore placement within the various resource reservoirs in the Horn River Basin. This paper will discuss the compromises that were made to the initial conceptual model that maximized learnings from the slant OH wellbore, and how the well was unexpectedly lost. Pressure interference data for future hydraulic fracturing models will be provided along with methods to describe how hydraulic fractures from nearby wells transect a well and interact with various reservoirs exposed within the OH segment of a slant wellbore.
Abstract In the last decades, the increasing use of Hydraulic Fracturing as a stimulation technique made possible to unlock reserves that were not economically producible until that moment. This has been possible due to the advances in horizontal drilling and to the improvements in completion technologies which made possible to cut down the costs associated to stimulation of low permeability reservoirs. The technological improvements of composite bridge plugs resulted in faster operations for deployment and post frac milling: this caused the Plug and Perf technique to be widely used on multi stage fracturing operations in the US during the "Shale Gas Revolution". This paper will describe a successful experience of exporting the Plug & Perf technology on a multi stage frac performed on a horizontal gas well, Sandstone reservoir, Southern Pakistan. The treatment consisted in six stages of propped hydraulic fracturing using a High Temperature frac fluid system and achieving zonal isolation by using composite bridge plug deployed with coiled tubing. All of the operations were performed rigless. Focus will be on the design, execution and post job analysis of this multi stage fracturing treatment with particular attention to the completion strategy and the operation sequence from the bridge plug setting to the milling operations and well clean up. Introduction The target reservoir has been reached with a 6" horizontal drain of about 1000 m length and completed with a 4½", 15.1ppf P110 cemented liner. A total of 6 stages were pumped to create transverse fractures across the entire pay in order to achieve an effective coverage of target layer. Plug and perf technique using E coil was used to complete with a single run the plugging of the early stimulated zone and perforating the next zone to be fractured. To allow production in commingle from the different stimulated intervals, a 3.5" OD milling motor was M/U and RIH on CT as it is described in the Fig. 1. Based on the experience gained on unconventional plays, the well has been designed 'toe up' to help the water unloading: in this configuration, the bulk volume of liquid accumulation is occurring downstream of the productive interval, providing more gas velocity to sweep the liquids and therefore allowing an easier and faster water flow back. The wireline logs recorded in the pilot hole and along the drain shown a reservoir permeability ranging from 0.01 to 0.1 mD, and an average porosity of 13 % with a water saturation of 70 %. The Reservoir Model in FracPro PT chosen is "Lithology Based description". The initial mechanical properties for the interested levels were estimated from the available data from the offset wells and have been calibrated after the diagnostics injection tests.
Abstract The Salak field is the largest developed geothermal resource in Indonesia. Steam production levels have been maintained at or above the rated power plant capacity for 15 years through periodic infill drilling and injection realignment. The reservoir management strategy for Salak involves injecting separated brine into deep wells on the margins of the reservoir where permeability is known to be low. A technique that has been used to enhance permeability in new injection wells combines hydraulic and thermal fracturing. This involves complex rock/fluid interactions and heat transfer relationships that must be considered in order to design appropriate injection rates, pumping times, and injection temperatures. This paper describes the techniques used to characterize candidate wells and interpret surveillance data collected during long-term cold water injection experiments. Analyzing continuous measurements of well injectivity along with pressure transient data taken periodically shows the evolution of enhanced permeability during stimulation. A high degree of success has been achieved using these techniques at Salak, with significant improvements in well injection capacity. These results provide additional alternatives for managing injection to increase the ultimate heat recovery from the reservoir. Introduction The Salak geothermal field is located within a protected forest about 60 km south of Jakarta. Geothermal operations are conducted pursuant to contracts with Pertamina (the Indonesian National Oil Company) and PLN (the Indonesian National Electrical Utility Company). The first exploration and appraisal wells were drilled at Salak from 1982 through 1986 and the first 110 MW (2 x 55 MW) power plants started commercial operation in March 1994. Between 1995 and 1997, four additional power plants (4 x 55 MW) were built at Salak. PT. Indonesia Power, a subsidiary of PLN, operates Unit 1–3 while Chevron Geothermal Salak, Ltd. operates Units 4–6. In 2002 the output of Units 4–6 was increased to 65.6 MW each bringing the total generation capacity of Salak to 377 MW and making it one of the six largest geothermal fields in the world. Formulating effective injection strategies has proven to be the most challenging aspect of field management. The initial development plan required injecting separate brine which is significantly below original reservoir temperature in fairly close proximity to production wells. A surveillance program including tracer tests, chemical monitoring, microseismic monitoring and pressure-temperature surveys of individual wells has been carried out since production commenced in order to monitor the impact of injection. As the breakthrough of chemical and thermal fronts was observed, injection was gradually moved to the field margins. This has resulted in expansion of the area available for drilling infill production wells while several former injection wells have been converted to production after allowing sufficient time for thermal recovery. Robust data gathering and monitoring programs have played an important role in realigning injection to optimize heat recovery from the reservoir (Acuña, et al., 2008).
This paper describes a research project whose objective was to develop a controlled propellant burning process that would produce fractures in vertical wells. The choice of propellant was restricted by a set of criteria. A series of tests were performed to characterize the burn rate and the gas generation rate as a function of pressure after a suitable propellant was found. The data from the tests were reduced to empirical expressions. These mathematical expressions describing the burning of the propellant, along with compressible flow theory, and the fracture mechanics of the formation, were used to develop a fully coupled computer code which describes the entire fracture process as a function of time. Finally, a test was performed to check the operational procedures, reliability of the ignition sequence, and gas generation capability of the propellant.
Conventional theories predicting borehole breakdown pressure assume breakdown occurs when the tangential stress at the borehole exceeds the tensile strength of the formation. Fracturing tests conducted during the DEA-13 joint industry project, however, showed that when drilling fluid project, however, showed that when drilling fluid was used as an injection fluid, borehole breakdown did not occur until the well pressure significantly exceeded the pressure which resulted in a tangential stress equal to the rock tensile strength even with a large surface flaw. The test results have shown that all drilling muds have a tendency to seal narrow natural fractures or fractures created by high borehole pressure. The sealing effect of the mud pressure. The sealing effect of the mud stabilizes fractures and prevents fracture propagation. This effect is one of the primary propagation. This effect is one of the primary factors for controlling wellbore stability. In this paper, a theory of fracture initiation and fracture propagation around a borehole whose stability is enhanced by drilling fluid interaction, has been developed and shown to be consistent not only with all the DEA-13 laboratory results, but also with various field evidence. The results show that lost circulation pressure is highly dependent on the Young's pressure is highly dependent on the Young's modulus of the formation, wellbore size, and type of the drilling fluid, although the conventional theories have ignored these facts.
Since Anthony Lucas introduced drilling mud as a circulation fluid to remove drill cuttings and cool the drill bit, millions of wells have been successfully drilled. Despite the inherent nature of formation strength heterogeneity, irregularity of boreholes and high borehole pressure fluctuations from surging, many wells have been drilled with relatively few problems. Such high stability of boreholes cannot be explained by any conventional theories (Ref.2 to 6) which estimate borehole stability from only the stress state around a borehole. Two roles of drilling fluid for stabilizing the borehole are well known: (a) supporting the borehole wall with hydrostatic well column pressure; and (b) laying down low-permeable cake pressure; and (b) laying down low-permeable cake to prevent pore pressure build-up and maintain high effective stress on the formation. These roles have been introduced in conventional theories. Any continuum theories developed in the past calculate stress state or effective stress state at the borehole surface and judge the lost circulation pressure based upon whether the effective stress exceeds tensile rock strength (zero tensile strength if existence of cracks is assumed). Because conventional theories are based upon only stress concentration around a borehole, they cannot explain commonly observed field phenomena such as borehole size effect, elastic modulus effect, and effect of mud type upon lost circulation pressure.
Drilling fluids contain solids which form bridges in the fracture aperture. Minute cracks are plugged by solids contained in drilling fluids. plugged by solids contained in drilling fluids. Although these functions of drilling fluids are well known, they have never been introduced into theory.
DEA-13 experiments (Ref.1) demonstrated that, before borehole breakdown occurs, a stable fracture develops. The fracture aperture is sealed by drilling fluid solid bridging over the fracture inlet. The borehole breakdown then occurs when the drilling fluid begins to enter into these fractures.
Another phenomenon found in these tests was that a narrow fracture tip zone exists which cannot allow drilling fluid invasion.
The equilibrium acid fracturing technique has been developed to stimulate wells in the Wasson San Andres Denver Production Unit. This new treatment technique maximizes acid contact time with the fracture faces while allowing control of the created fracture dimensions. Maximum acid contact time is essential to create highly conductive etched pathways on the fracture faces of cool dolomite formations which react slowly with acid. Control of fracture dimensions is important in the Denver Unit San Andres because fractures tend to grow uncontained in at least one vertical direction and the oil column is bounded by permeable gas bearing intervals above and permeable water bearing intervals below.
Using this technique, a fracture of desired dimensions is first created by injecting acid at fracturing rates. The volume of acid required to create the desired fracture dimensions is determined by a two dimensional fracture geometry program using design parameters determined from mini-frac testing and laboratory testing. Injection is then continued at reduced rates which maintain equilibrium with the fluid leak-off rate from the created fracture faces. By maintaining equilibrium between injection and leak-off, the created fracture can be held open without significant further fracture extension. Equilibrium is achieved in the field by maintaining the injection pressure below the fracture extension pressure, but above the fracture closure pressure determined by mini-frac testing.
The background and theory of this technique will be presented in this paper along with design procedures, field examples, results, and conclusions. A comparison of the results of the equilibrium acid fracture treatments to the other acid stimulations performed in the Denver Unit is also shown.
IntroductionThe Denver Unit is one·of several production units in the Wasson San Andres Field located in the western Texas counties of Gaines and Yoakum. The location of the Denver Unit within the field is shown in Figure 1. The San Andres formation is a Permian dolomite. The target interval is at a depth of about 5000'. The Wasson San Andres Field was discovered in 1936. The Denver Unit was formed in 1964 and waterflooding began at that time. CO2 flooding in the Denver Unit was started in 1984 and expansion is ongoing today.
Kuriyagawa, H. (National Research Institute for Pollution and Resources) | Matsunaga, I. (National Research Institute for Pollution and Resources) | Yamaguchi, T. (National Research Institute for Pollution and Resources) | Zvvoloski, G. (Los Alamos National Laboratory) | Kelkar, S. (Los Alamos National Laboratory)