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The prescribed treatment for market- and virus-induced oil price collapse is to quickly slow production growth. Two US shale companies moved swiftly to cut the pace of drilling and completions, but it is too soon to know if that will have any impact. Through data gathering, machine learning, and the use of a supercomputer, a non-profit organization in Texas is seeking to boost oil and gas production on land owned by the states’ two largest university systems. This paper reviews two newly developed novel completion systems that significantly reduce time spent performing multistage stimulation in environments where cost and consequence of failure are high.
A new Protocol ("DMX") is presented for 3d DFFN (Discrete Fault and Fracture Network) modelling, a numerical code developed over the last 20 years in order to converge towards a more realistic Discontinuity (fault and fracture) Network representation in space. The protocol introduces the following new features: Fracture interaction, truncation, termination and cross cutting in 3d space based on newly designed collision algorithms and fracture propagation principles; Modelling at any scale range of unlimited basic 3d fracture shapes, specific 3d fracture morphology, and 3d fracture aperture types; A complete integration between classical geological/geomechanical drivers such as stress ellipse, fault zones with 3d slip vectors, and different fold models (axial plane, fold axis and bedding orientation conditioning), geological assembly modelling such as joint spacing and set dependency, offset/faulting, and probabilistic conditioning of any of the parameters and drivers. Examples of the application of the protocol are presented to illustrate few of the unlimited amount of combinations that can be generated in 3d space. Furthermore, an example of the complete flow chart of a calibration to real observed cases is provided. The protocol constitutes a complete game change and opens a range of technological challenges for the future applications in Mining, Civil Engineering and Conventional and Unconventional Oil and Gas Exploration and Production.
Zulkarniev, R.N. Asmandiyarov Gazpromneft NTC LLC, RF, Saint-Petersburg The paper compares various methodological approaches for factor analysis of the success of well interventions. Particular attention is paid to the factor analysis of the drilling results of multistage fractured horizontal wells. Improved analysis tools based on the integral method and the use of a regression model are proposed. Correct consideration of all technological factors at the planning stage of well interventions makes it possible to avoid overestimating or underestimating the potential of new drilling. The use of the considered tools for a number of new pads allowed us to systematically correct geological and simulation models, correctly estimate the potential of new wells and make timely decisions regarding the need for engineering operations and future drilling.
Since the first frac in 1954, around 250 of the 3000 exploration and production wells in the Netherlands have been hydraulically fractured. This study focusses on about 50 of the more recent fracs, of which sufficient production data, reservoir information and hydraulic fracture properties could be obtained for economic and data analysis.
For each well, the production history has been analyzed with a commercial rate transient analysis software package. About half of the wells have a pre-frac production history while the other half have been hydraulically fractured immediately after drilling. For wells with pre- and post-frac production data two history matched analytical models were made. Those models were subsequently used to create two production forecasts, to determine the incremental production profile and to calculate the economic value added by each frac. For wells without pre-frac production data the history matched post-frac model was used two create two production forecasts, one with and one without a hydraulic fracture in place.
The calculated economic values have been combined with reservoir properties (permeability, GIIP, stratigraphy, etc.) and frac data (proppant type, amount of fluid used, amount of proppant pumped, etc.), to form a dataset which was analyzed using a commercial data analysis tool to investigate perceived correlations.
The results show that practically all analyzed fracs resulted in a production improvement, and most of the fracs resulted in positive economic value added. However, some resulted in an economic grey area (below EUR 5 million incremental discounted cash flow), and one frac even resulted in a negative value.
Many reasons can be given for the distinction between economic and uneconomic projects. This paper shows that although multiple attributes influence the calculated economic value, some generic observations can be made. There is apparently no correlation between PI improvement, skin or kh and economic value. Remaining GIP is definitely important for economic value, but no generic correlation for reservoir pressure can be made. It was shown that wells often see more connected GIIP after fraccing. The results show that fracs in reservoirs with 80% depletion can still result in very economically beneficial projects, especially if the fracs increase the connected GIIP. Frac properties might very well be important for the determination of the economic value of fractures. However, no clear correlation between economic value and frac half length or proppant size could be found. On the other hand, the results show that larger amounts of (any) proppant pumped seem to lead to higher economic value. Last but not least, a relation between PI improvement and pre-frac skin was found.
The study presented is the first portfolio analysis of fracced conventional gas wells in The Netherlands. Input and methods have been checked and results have been shared with several experts outside our organization.
ABSTRACT: In the framework of the In-situ Stimulation and Circulation (ISC) experiment Fiber-Bragg-Grating (FBG) and Brillouin strain sensing systems were installed to monitor deformation during six hydraulic shearing and six hydraulic fracturing experiments. Three boreholes were dedicated to strain monitoring. Both systems are installed in the same boreholes, offering a unique opportunity to compare these systems with respect to their applicability in hydraulic stimulation tests. A total of 60 FBG sensors with 1 m base length were installed across fractures, shear zones and intact rock. Along the entire borehole length, pre-stressed optical cables for Brillouin distributed strain (DBS) sensing were embedded in grout with two installation methods: a bare cable and a cable packed and fixed with glue every 0.65 m. The strain signals were compared as time series for a given borehole depth and as profiles along the borehole axis. The study reveals that the FBG system gives a high accuracy (0.04 μ-strain) and temporal resolution (>1s) with pointwise measurements. The bare DBS leg yield good quantitative strain data with poorer strain accuracy (>500 times poorer than FBG) and poorer temporal resolution (factor of >100). The packed DBS leg provide no meaningful information about the strain field
Deformation is the fundamental kinematic variable in rock mechanics. Commonly, it is expressed as strain, which is the non-rotational component of the deformation tensor (i.e., the spatial derivative of the displacement field) (Jaeger et al., 2007). Strain or deformation measurements are important for a broad range of applications: from lab-scale test (e.g., compressional tests), over structural engineering (e.g., bridges; Glisic et al., 2011) to geotechnical engineering (e.g., mining, tunneling; Valley et al., 2012) and to natural hazards (Moore et al., 2010). Conventionally, in-situ deformation measurements are executed using multi-point borehole extensiometers (MPBX) or inclinometers that present strong limitations in terms of sensitivity and spatial coverage(Madjdabadi et al., 2016). Fiber-optics-based strain monitoring systems are more and more used in geotechnical context, since they combine high resolution and long durability with insensitivity to electromagnetic noise and moisture (Madjdabadi et al., 2016).
SLIDE 1 - BACKGROUND Welcome and gratitude. Welcome everyone and thanks for coming today. Before we begin, I'd like to acknowledge the SPE Foundation for funding the SPE Distinguished Lecturer Program through its members donations. I'd also like to thank my employer, BP, for allowing me to come to deliver this message today. My name is David Spain, and I am a member of the BP Upstream Technology Group, Unconventional Reservoirs Flagship.
After drilling out cement at the start of a new wellbore section, a formation integrity test is routinely performed to verify the integrity of the new formation and the cement at the casing shoe. Test results can have large impacts on the drilling operation, such as motivating remedial cementing operations, changing the drilling fluid mass density or the setting depth of casing strings. Interpretation of the test results are often made difficult for a number of reasons, including significant fluid losses to permeable formations, large friction pressure losses, compression of trapped air and unstable pump operation.
This paper presents a new supervisory system providing real-time test analysis and automated result interpretation of pressure integrity tests, leak-off tests and extended leak-off tests. Based on a minimum of preconfigured user input, the system covers all test phases, from pressurization, fracture propagation to shut-in and flowback. Rather than relying on computationally intensive modelling of downhole physics, regression techniques are applied to relate surface pressure to injected fluid volume, shut-in duration and volume or time in flowback.
System compliance and fluid leakage rates are determined prior to leak-off using a nonlinear regression model. The calibrated model is in turn used to generate prediction intervals for detecting leak-off and fracture pressures. Extended leak-off interpretation is based on the system stiffness approach, in which fracture closure is associated with a reduction in system compliance. We apply regression techniques to search for fracture closure during shut-in and during flowback. The system identifies unexpected test behavior and triggers warnings by continuously evaluating key test metrics such as leakage rate, system compliance and surface pressure during each test phase.
The development is based on few model assumptions. Low-pass filtering combined with regression techniques ensure that the system is capable of analyzing field tests of variable quality and with noisy surface sensor measurements. We assess the performance based on historical tests that are representative of the variation in possible pressure-volume behaviors and with typical noise levels on input sensor signals. The system output corresponds well with the original manual test interpretations, and provides in most cases reliable determination of leak-off and fracture pressures, fracture propagation and fracture closure pressures. Real-time test supervisory functionality in addition to standardization of test interpretation and data storage are immediate benefits of system implementation.
A site-specific rock mass classification scheme was developed as part of the geotechnical engineering design for a new build nuclear power station in the UK. A robust and explicit classification scheme was used to interpret and classify all the available data, not just that from the most recent investigations, in a clear, unambiguous and efficient manner. To achieve this objective, the scheme had to be sufficiently simple that it could be applied to historical boreholes. This paper describes the process of selecting the input parameters for the classification scheme; the pilot study that was then undertaken to test its robustness and utility for geotechnical design; and the results of its application for the whole site. Two input parameters were selected: fracture spacing and weathering grade. Using these parameters, the bedrock was divided into five groups. The rock mass classification was then used to provide Geological Strength Index values. It was also viewed in a three-dimensional model, enabling easy identification and correlation of faults.
This paper presents the development and application of a site-specific rock mass classification scheme as part of the geotechnical engineering design for Horizon Nuclear Power's Wylfa Newydd new build nuclear power station in the UK. It describes the rationale for developing a site-specific classification scheme and the process of selecting the input parameters during the scheme's development. A pilot study was undertaken to test the classification scheme's robustness and utility for geotechnical design. This paper describes the implementation of the scheme, advantages and limitations of the classification, and how it could be used for other projects.
The proposed Wylfa Newydd power station site is located on the northern coast of Anglesey, northwest Wales, as shown in Figures 1 and 2.
The site is located in a geologically complex area; superficial deposits, predominantly of Quaternary glacial origin, overlie metamorphic bedrock belonging to the Monian Supergroup of Late Pre-Cambrian and Early Cambrian age (British Geological Survey, 2014). The site is crossed by igneous intrusions and faults of varying persistence and orientation.
Multiple fractured horizontal wells (MFHWs) are considered as the most effective stimulation technique to improve recovery from low permeability reservoirs particularly tight and shale assets. The understanding of the complex flow behaviour and predicting Productivity Index (PI) of these wells are vital for exploitation of such reservoirs. These data also affect the optimum hydraulic fracture design and the long term well performance.
The, analytical or semi analytical, models previously proposed cannot accurately describe the flow behaviour around MFHWs due to lack of capturing the complexity of the flow especially the fracture-to-fracture interference effects. The fine grid three dimensional (3D) simulation approach is also costly and cumbersome. In this work, we followed a novel approach to develop a new equation that can predict MFHWs performance under pseudo-steady state flow conditions in tight reservoirs.
An in-house programming code, which automatically creates batch files, reads input data and stores relevant output data for each simulation, was coupled with a fine grid 3D reservoir model to generate the required large data bank. For these simulations, the pertinent parameters (matrix permeability, number of fractures and fracture permeability, spacing, width, length and conductivity) were varied over wide practical ranges based on the full factorial experimental design method.
The overall as well as the individual impacts of the parameters on PI, as the output variable, were evaluated by various statistical analyses techniques, including Spearman's rank correlation coefficient, under different prevailing conditions. It is shown, for instance, that increasing the fracture width and permeability does not result in a significant monotonic increase in PI while changing fracture length, spacing and numbers influences PI greatly.
Moreover, a new expression is proposed that relates MFHWs-PI to PI of the horizontal well with a single fracture and to number of fractures and dimensionless fracture spacing parameters by applying the symbolic regression technique. The cross validation results show that the proposed equation is general, reliable and simple for prediction purposes because it benefits from limited and appropriate dimensionless numbers with excellent values of fitting indices.
This study expands our understanding of flow behaviour in tight reservoirs and provides an invaluable engineering tool that can facilitate simulation of flow around MFHWs and quickly predict their well performance. The new IPR equation can also be used for optimising MFHWs design.
Rück, M. (German Research Centre for Geosciences) | Rahner, R. (German Research Centre for Geosciences) | Sone, H. (German Research Centre for Geosciences) | Dresen, G. (German Research Centre for Geosciences)
We studied the initiation and propagation of mode II fractures in granite and sandstone under confining pressure to investigate the controls on shear fracture propagation in rocks. An asymmetric loading set up was used to induce a fracture in cylindrical rock samples under confining pressure between 0-20 MPa. We achieved quasi-static fracture propagation with a refined AE feedback displacement control. This technique prolongs the fracturing process up to 42 hours, provides a higher AE resolution and thereby allowed the distinction of two different stages in shear fracture propagation. Granitic samples form vertical fractures in the strain strengthening stage that branch and stop propagating at peak stress. Simultaneously at peak stress a distinct diagonal fracture nucleates on the loaded side of the vertical fracture. During strain weakening we observed stable growth of this second diagonal fracture until the sample lost its integrity. On the other hand sandstone samples only form the diagonal fracture during the strain weakening stage. Analysis of AE source type and hypocenter as well as microstructural analysis indicate that porosity, either intrinsic (sandstone) or deformation inflicted (granite), primarily influences this fracture nucleation and propagation behavior for both rock types.
Fractures form as microscopic cracks coalesce into a planar structure, which can be captured by monitoring acoustic emissions (AEs). Macroscopically, rocks will fracture in the mode (I or II) corresponding to the mode of loading determined by the orientation of the fracture relative to the stress state. However at a microscopic scale, both modes of fracturing can be found in what may appear to be a pure mode of fracturing at the macroscopic scale [1, 2]. According to the acoustic emissions observed during rock fracturing experiments, shear-, tensile-, and compression-events all occur during macroscopic mode II fracture propagation . On a microscopic scale on the other hand, increased confining pressure suppresses the occurrence of mode I fractures and supports the occurrence of mode II fractures . These observations demonstrate the complexity of rock fracturing on a microscopic scale and thereby raised a controversy about the validity of macroscopic fracture modes. The existence of a fracture criterion for mode II is still debated in the literature [5, 6]. To study this, many authors used acoustic emissions to stabilize the fracture process [1, 7, 8, 9, 10]. By controlling the load in response to the intensity of the observed AEs, the rate of fracturing was varied and fracture propagation could be visualized in detail.