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Brinkley, Kourtney (Devon Energy) | Ingle, Trevor (Devon Energy) | Haffener, Jackson (Devon Energy) | Chapman, Philip (Devon Energy) | Baker, Scott (Devon Energy) | Hart, Eric (Devon Energy) | Haustveit, Kyle (Devon Energy) | Roberts, Jon (Devon Energy)
Abstract This case study details the use of Sealed Wellbore Pressure Monitoring (SWPM) to improve the characterization of fracture geometry and propagation during stimulation of inter-connected stacked pay in the South Texas Eagle Ford Shale. The SWPM workflow utilizes surface pressure gauges to detect hydraulically induced fracture arrivals athorizontal monitor locations adjacent to the stimulated wellbore (Haustveit et al. 2020). A stacked and staggered development in Dewitt County provided the opportunity to jointly evaluateprimary completion and recompletion efforts spanning three reservoir target intervals. Fivemonitor wells at varying distances across the unit were employed for SWPM during the stimulation of four wells. An operational overview, analysis of techniques, correlation with seismic attributes, image log interpretations, and fracture model calibration are provided. Outputs from this workflow allow for a refined analysis ofthe overall completion strategy. The high-density, five well monitor array recorded a total of 160 fracture arrivals at varying vertical and lateral distances, with far-field fracture arrivalsprovidingsignificant insight into propagation rates and geometry. Apronounced trend occurred in both arrival frequency and volumes pumped as monitor locations increased in distance from the treatment well. Specific to target zone isolation, it was identified that traversing vertically in section through a high stress interval yielded a 30% reduction inarrival frequency. An indirect relationship between horizontal distance and arrival frequency was also observed when monitoring from the same interval. A decrease in fracture arrivals from 70% down to 8% was realized as offset distance increased from 120 to 1,700 ft. The results from this study have proven to be instrumental in guiding interdisciplinary discussion. Assessing fracture geometry and propagation during stimulation, particularly in the co-development of a stacked pay reservoir, is paramount to the determination of proper completion volume, perforation design, and well spacing. Leveraging the observations of SWPM ultimately provides greater confidence in field development strategy and economic optimization.
Abstract Devon Energy conducted a Surface Microseismic Monitoring Project to compare various microseismic acquisition geometries targeting the Eagle Ford (EGFD) formation. Two horizontal wells were drilled, Well A at a depth of roughly 12,350 feet with a lateral length of ~5,500 feet in the Upper EGFD, and Well B at a depth of roughly 12,500 feet and extending ~6,000 feet in the Lower EGFD. The goal of the Microseismic Monitoring Project was to benchmark different acquisition geometries when monitoring the hydraulic fracture stimulation in Well A. In benchmarking surface array acquisition geometries, the objective is evaluated not only in amount of hypocenters located and the precision and accuracy of those events, but the cost, adaptability and added source processing that can be done with the acquired data. To assess several geometries, the hydraulic fracture stimulation of Well A was monitored using a patch array and a radial array. The events imaged by these arrays were compared to a 3 array consisting of a much denser sampled 3C 3D seismic geophones. The radial array design consisted of ten radial arms evenly spaced emanating outward 18,000 to 24,000 feet from the well head. The patch array consisted of thirty-one patches, forty-eight instruments per patch in sets of twelve, evenly spaced throughout the same area ranging from 3,000 to 25,000 feet from the well head. In monitoring a frac, both layouts were tested for precision and accuracy of hypocenters (x,y,z) and source mechanisms. The sampling of the radial array was superior, determining more hypocenters with higher accuracy and a better-constrained velocity model. The patch array appears to have been too sparsely spaced with many patches too far from the well. Patches located on the nodal plane also provided no contributions to the focal mechanism calculations. From this project, a potential strategy for both the patch and radial array can be achieved with proper planning for the area. Well-designed acquisition geometries can in turn increase the knowledge provided by microseismic monitoring for reservoir characterization. We look forward to pursuing these questions on this project and as well as on future projects.
Vaughan, Jeffrey K. (Vaughan Exploration, Inc.) | Palmer, Ron (Macpherson Oil Co.) | Benitez, Andres (Baker Hughes Incorporated) | Bowser, Aaron (Baker Hughes Incorporated) | Graham, Adam (Baker Hughes Incorporated) | Hart, Eric (Baker Hughes Incorporated) | Hood, James (Baker Hughes Incorporated) | Long, Justin (Baker Hughes Incorporated) | Vigil, Micheal (Baker Hughes Incorporated) | Williams, Tandre (Baker Hughes Incorporated) | Aghassi, Arash (Baker Hughes Incorporated)
Abstract Directional drilling, particularly in conjunction with reservoir navigation (i.e., geosteering), is used to land wells at preplanned points in a reservoir and to optimize the wellbore placement of production sections with respect to reservoir boundaries and fluid contacts, by adjustment of well trajectories in real-time. Geosteering is accomplished and facilitated by the recognition of approaching conductivity contrast boundaries not yet penetrated by the wellbore by the use of deep reading tools and geologic models used to predict the boundaries approach. The decision making process needs to be quick and efficient as drilling progresses whilst decisions and interpretations are being made. Using deep resistivity images, and example templates for interpretation, assists in timely decision making and aid in simplifying what is a complex problem. The efficacy of the deep resistivity image interpretation concepts are illustrated by comparison of motifs observed in field data in complex channel sand environments to synthetic models and numerically modeled images of observed instrument responses. Addition of receiver antennas transverse to the axis of the coaxial antenna array permits acquisition of information on the direction to the boundary or contact. The physics of the method dictate that there is little or no detectable signal from the formation except in the presence of a conductivity contrast boundary within the (relatively large) volume of investigation of the antenna array. Electromagnetic radiation propagates considerable distances into resistive reservoir rocks and fluids, enabling electromagnetic logging-while-drilling instruments to detect such boundaries and estimate their orientation and distances in space relative to the wellbore. Images constructed from a combination of the usual coaxial dipole electromagnetic signal augmented by signals from transversely mounted receiver coils offer a visual interpretation option for the responses of logging-while-drilling propagation instruments. However, methods for interpretation of standard borehole resistivity images cannot be applied directly to the interpretation of deep resistivity images. These deep resistivity images vary with hole inclination, conductivity contrasts, and geologic structure, but usually produce a recognizable pattern, called a motif, that can be diagnostic of the geological_structure in the vicinity of the wellpath. Moreover, the motifs can be organized into a manageable number of themes that aid in their interpretation. Proper interpretation of the themes and motifs not only aids in geosteering decisions, but also enhances conventional formation evaluation by bringing an element of directionality to resistivity measurements that has not been possible in the past. In this paper we present real life examples from a challenging environment in the middle east, where simple motifs can help identify common responses and in future speed and aid interpretation for both the contractor and the client. In addition, the naming of these assists in the training of new Navigators, and clients alike. As the industry expands and the real-time decisions are pushed onto often less experienced personnel, and with the rapid change in technology the industry experiences, making interpretations simpler and more memorable is of key import.
Directional drilling, particularly in conjunction with reservoir navigation (i.e., geosteering), is used to land wells at preplanned points in a reservoir and to geosteer production sections of wells. The objective is to optimize the wellbore placement with respect to reservoir boundaries and fluid contacts, by adjustment of well trajectories in real time. Geosteering is accomplished and facilitated by the recognition of approaching conductivity contrast boundaries not yet penetrated by the wellbore. Addition of receiver antennas transverse to the axis of the coaxial antenna array permits acquisition of information on the direction to the boundary or contact. The physics of the method dictate that there is little or no detectable signal from the formation except in the presence of a conductivity contrast boundary within the (relatively large) volume of investigation of the antenna array. Electromagnetic radiation propagates considerable distances into resistive reservoir rocks and fluids, enabling electromagnetic logging-while-drilling instruments to detect such boundaries and estimate their orientation and distances in space relative to the wellbore. Images constructed from a combination of the usual coaxial dipole electromagnetic signal augmented by signals from transversely mounted receiver coils offer a visual interpretation option for the responses of logging-while-drilling propagation instruments. However, methods for interpretation of pad-derived borehole resistivity images cannot be applied directly to the interpretation of deep resistivity images. These deep resistivity images vary with hole inclination, conductivity contrasts, and geologic structure, but usually produce a recognizable pattern, called a motif, that can be diagnostic of the geological structure in the vicinity of the wellpath. Moreover, the motifs can be organized into a manageable number of themes that aid in their interpretation. Proper interpretation of the themes and motifs not only aids in geosteering decisions, but also enhances conventional formation evaluation by bringing an element of directionality to conductivity measurements that has not been possible in the past. The efficacy of the deep resistivity image interpretation concepts are illustrated by comparison of motifs observed in field data to synthetic models and numerically modeled images of observed instrument responses.
Images of a borehole wall have been in use for more than 40 years. First imaging technologies were acoustic borehole imagers, called televiewers. These essentially constructed a time-of-flight cross sectional image of the borehole shape, and a reflectivity image of the borehole wall based upon the amplitude of the first arrival. Borehole televiewers were joined in the mid-1980s by electrical borehole imagining using small electrodes arrayed on pads in contact with the borehole wall. Both image types have been used as a surrogate for coring, with applications that include fracture detection and characterization, and formation dip quantification. Most recently, LWD bulk density and gamma ray images have been added to the repertoire of borehole images. The formation features imaged by these devices share the common property that they are all located at, or very near, the borehole-formation interface.
Conventional, and so-called, “deep reading” resistivity arrays derive their signals from a much larger volume of formation.
Abstract A resistivity tool with a large depth of investigation (greater than 30 meters in ideal conditions) has been designed and used in the North Sea Grane field for over three years. An azimuthal resistivity tool with a depth of detection of about 6 m in ideal conditions has now been added to the bottomhole assembly. When the deeper measurement detects a conductive zone there is no information about the direction to the target because the measurement has azimuthal symmetry. The shallower azimuthal measurement will be able to give the direction to the conductive zone when it comes within the depth of detection of the tool. The target for this effort is a thick reservoir (about 60 meters) that has a long, gradual transition from a resistivity of about 300 ohmmeters at the top of the sand to the water zone of about 0.5 ohmmeters at the bottom. A shale formation of about 1.0 ohmmeter is found both above and below the sand. A deep resistivity tool, a normal propagation resistivity tool, and an azimuthal resistivity tool are all used to place the well in the ideal position to produce the reservoir. The azimuthal tool has no response in a homogeneous formation. The result is a better depth of detection because the signal from the target zone does not have to be removed from a constant background signal. Unfortunately, a gradient is not a homogeneous formation and the result is a background response roughly 10 times the normal noise floor of the tool. However, the shallow measurements of the traditional axial propagation resistivity tool are used to estimate the response of the azimuthal tool to the resistivity gradient. The difference between the estimated response and the actual response is a better indication of a nearby conductive bed. Both synthetic models and actual data are used to show how the combination of the three resistivity tools can geosteer in this complicated environment. In particular, this combination is able to distinguish between a shale body above the tool and a shale encroaching from below. Introduction The StatoilHydro ASA operated Grane oil field is located in the Norwegian North Sea block 25/11 (Fig. 1), approximately 200 km northwest of Stavanger. The field has been in production since September 2003 and has a cumulative production of 295 million barrels of oil per May 2008. The reservoir consists of massive Heimdal Member turbidite sandstones of Paleocene age, enclosed within the Lista Formation claystone. The predominantly fine-to-medium-grained, moderate-to-well-sorted reservoir sandstones show excellent reservoir properties with porosities of 30–33 porosity units and permeabilities typically in the 5–10 Darcy range (Helgesen et al., 2005b). Experience has shown that shale intervals may be encountered when drilling horizontal production wells, particularly close to the reservoir base. Image data and dip calculation (based on azimuthal resistivity data) indicate that the shale intervals have steep boundaries. This suggests a post-depositional origin, associated with folds and faulting (Helgesen et al., 2005b). The highly viscous (12 cP) biodegraded oil of the Grane field has a density of 895kg/m3, close to that of the formation water, which is 1018kg/m3. Due to the small density contrast, a very long transition zone above the oil/water contact has developed throughout the field. This transition zone is clearly defined on all resistivity logs.
Abstract With the use of both azimuthal propagation resistivity main and cross component data, the resistivity anisotropy and its dip and azimuth angles of a massive formation (anisotropic shale or laminated sand) can be determined. The accuracy of the determined parameters depends on the amount of available data. A minimum amount of data are two frequency main components and real and quadrature cross components. The boundary effects will distort the solution eventually; however, the anisotropy enhanced processing will minimize the effects to extend the algorithm to a certain distance away from a boundary. Introduction The first decade of the 21st century has seen the end of the era of easily producible oil fields. The increased competition for oil from the newly developing countries has renewed interest in unconventional reservoirs such as gas and oil shales. There is a substantial amount, by some estimates 30%, of hydrocarbon locked in laminated, low-resistivity, low contrast, and anisotropic shales. Understanding the effects of anisotropy in reserves assessment and structural interpretation is thus becoming more and more important. The properties of anisotropic formations have been a subject of research for a long time. It was shown that the measurements in anisotropic formations can be used to determine the dip and strike of bedding structure (C. Schlumberger et al., 1920, 1934). If the borehole is neglected, a normal or a lateral galvanic device will measure longitudinal resistivity ("paradox of anisotropy") (Maillet and Doll, 1932; Kunz and Moran, 1958). The study of the response of induction tools in layered anisotropic media shows that the "paradox of anisotropy" remains valid for the induction tools (Moran and Gianzero, 1979). The induction response to dipping anisotropic beds can be used in iterative method of correcting the resulting distortion in the longitudinal resistivity (Klein 1991) It has not been possible to derive dip and azimuth angles from the standard logging while drilling propagation resistivity measurement without knowledge of formation anisotropy. The traditional MWD and induction tools with coaxial transmitters and receivers can measure the longitudinal resistivity but require additional information to determine anisotropy and associated dip (Hagiwara 1995, 1996). The introduction of modern tools with transmitter and receiver coils perpendicular to the main axis provides the necessary additional information to determine both anisotropy and relative dip in addition to the longitudinal resistivity (Zhdanov et al., 2001). Examples of such tools are logging while drilling azimuthal propagation resistivity and wireline 3D Explorer. The LWD Azimuthal Propagation Resistivity (APR) has coaxial transmitter and planer (perpendicular to tool axis) receiver pairs. The conventional APR processing tends to suppress anisotropic effects and enhance sensitivity to remote beds, so that it can provide information about the direction and distance to the approaching bed boundary. However, the measurements can also be processed differently to maximize the anisotropy effect and minimize the sensitivity to remote bed boundaries. By doing so, the azimuthal measurements add information about the formation that can be combined with the standard Multiple Propagation Resistivity (MPR) measurements to yield the resistivity anisotropy, dip and azimuth angles. In this paper, we first examine the azimuthal responses in an anisotropic formation. Then we describe a method and its applicable conditions for calculating resistivity, anisotropy and associated structural dip and azimuth angles from both azimuthal and standard propagation resistivity measurements. The approach is illustrated with both synthetic and field data.
Chemali, Roland E. (Halliburton Sperry Drilling Services) | Hart, Eric | Flynn, Tracey (INTEQ) | Meyer, Hal | Helgesen, Tron Bjelland (INTEQ) | Kirkwood, Andrew D. (INTEQ) | Merchant, Abbas | Berle, Alf Erik (INTEQ)
Abstract We illustrate the use of a new technology for navigating and characterizing various types of oil reservoirs. Real-time images from Azimuthal Propagation Resistivity measurements provide a "map" of the resistivity patterns up to several meters around the wellbore. In addition, recently developed processing and quantitative interpretation techniques help guide the placement of the well and provide a new perspective of the formation. When navigating in gas drive reservoirs, the azimuthal resistivity measurement is used to maintain the wellbore at a prescribed distance above the oil-water contact. With its exponential sensitivity to distance, the measurement is able to detect even small changes in the distance to the oil-water interface. In a few instances, the azimuthal information provided by the real-time deep resistivity images indicates probable coning due to offset well production. Similar principles are applied in high angle drilling of water drive reservoirs. The deep azimuthal information allows the drilling engineer to maintain the wellbore at a prescribed distance immediately below a shale roof. The deep resistivity image from the azimuthal resistivity measurement also makes it easy to distinguish the roof from the occasional approaching shale lens. Whereas shallower reading LWD image logs (e.g. Gamma Ray and Density) only indicate a geological feature proximal to wellbore, the deep reading azimuthal resistivity measurement can provide geologic structure information at the reservoir scale. Visual displays show the subsurface surrounding the wellbore; quantitative algorithms accurately compute the distance, direction, and apparent dip for reservoir related geological events. A new conductivity unit named "Transverse Siemens" is proposed to help quantify the new azimuthal propagation measurement. Introduction The main objective of reservoir navigation is to stay for long intervals in the target zone, while keeping clear, at appropriate distances from boundaries including reservoir tops, oil-water contacts, shale lenses and other similar events. Typically wells need to be placed immediately below the roof, or a few feet above the oil water contact for the most effective sweep. In other instances, wells are driven to access multiple reservoirs or compartments. Proper well placement has helped to produce millions of barrels of "attic oil" or avoid costly early water breakthroughs. Successes in reservoir navigation have become more noticeable to the industry in recent years, as they enable higher hydrocarbon recovery from some well known, large oil fields. Steering decisions during reservoir navigation must be made quickly and accurately as the drill bit advances. Therefore, real-time information to the navigation engineer needs to be timely, as complete as possible. When traditional LWD propagation measurements predict an approaching boundary, they lack critical information as to whether that boundary is approaching from above, below or the side. Evasive actions are entirely different for each instance. Until recently, reservoir navigation has relied on deep reading propagation resistivity, without azimuthal sensitivity, to anticipate as early as possible the intersection with an approaching boundary. In many cases, at the time of intersection, an imaging instrument such as azimuthal gamma helps identify the direction of entry. This solution leaves an obvious time gap between the early detection of the approaching boundary and the late identification of its direction. Navigation experts help fill this gap through experience and local knowledge, but the risk of error can be significant. A new azimuthal propagation resistivity LWD combines the early detection of the approaching boundary with an early indication of its azimuth of approach. As previously disclosed, the information is presented as deep reading images. Through years of extensive use by geologists, downhole image logs have become familiar and easier to read.
This paper describes a method for determining dip and azimuth values from a novel deep directional resistivity LWD measurement and testing of the method against computer models and field logs in the North Sea fields. Both synthetic and field data examples are shown to illustrate the method. The new measurement is able to define the direction and dip of approaching beds at a larger scale than borehole images. From a reservoir navigation standpoint, the added depth of investigation helps realtime decision making by anticipating boundary crossings well before they occur. In addition the new technology delivers an image of the formation, several feet away from the borehole wall. Through signal processing, fully compensated measurements remove environmental and tool noises, further improving the accuracy of the dip and azimuthal information. The dip is determined based on a unique property of the new measurement, i.e., the magnitude of the signal is nearly exponential in the distance to the boundary. We developed a method to determine the apparent dip using a direct relationship between apparent dip and the signal decay rate vs the distance to bed. The apparent dip and azimuth are determined whether or not the wellpath actually intercepts the approaching boundary. The method has been validated against synthetic and field data with accurate and consistent dip results.
Obtaining azimuth and dip information of adjacent geologic boundaries is a crucial but challenging task for reservoir navigation and formation evaluation. Azimuth information tells the driller the direction of geologic boundaries such as reservoir tops, oil-water contacts, and fault planes, whereas dip information tells how rapidly the drillstring is approaching or moving away from these boundaries. The dip information is also useful for determining reservoir boundaries, true bed thickness, structural dip, and other reservoir parameters. Classic LWD borehole imaging logs only provide dips and azimuths at shallow depths of investigation. Practically, the information is available only after the wellbore intercepts a boundary. Therefore, the dips and azimuths only reflect the geologic information in the close vicinity of the wellbore and may be disturbed by local variations in geology. In this paper, we describe new techniques for deriving dip and azimuth information from a new, deep directional resistivity measurement (Wang, et al., 2006, Bell, et al., 2006). The new measurement employs a cross-coil configuration that is specially designed to detect remote bed boundaries. The 16-sector data are collected while drilling and provide a unique determination of the direction of the approaching remote bed. The signal is purified to respond only to remote beds. Hence, the measurement is extremely sensitive to the apparent dip angle of the bed. The signal purification combined with the high-efficiency antennas give the directional resistivity measurement a large depth of investigation up to 17 ft. The large depth of investigation is crucial for geosteering and reservoir navigation. The dip of a remote bed boundary is determined from the azimuthal propagation resistivity measurement based on the fact that the tool response is a nearly exponential function of the distance to the boundary. The decay rate (slope) of the response is directly proportional to the apparent dip angle.