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Suarez-Rivera, Roberto (W. D. Von Gonten Laboratories) | Panse, Rohit (W. D. Von Gonten Laboratories) | Sovizi, Javad (Baker Hughes) | Dontsov, Egor (ResFrac Corporation) | LaReau, Heather (BP America Production Company, BPx Energy Inc.) | Suter, Kirke (BP America Production Company, BPx Energy Inc.) | Blose, Matthew (BP America Production Company, BPx Energy Inc.) | Hailu, Thomas (BP America Production Company, BPx Energy Inc.) | Koontz, Kyle (BP America Production Company, BPx Energy Inc.)
Abstract Predicting fracture behavior is important for well placement design and for optimizing multi-well development production. This requires the use of fracturing models that are calibrated to represent field measurements. However, because hydraulic fracture models include complex physics and uncertainties and have many variables defining these, the problem of calibrating modeling results with field responses is ill-posed. There are more model variables than can be changed than field observations to constrain these. It is always possible to find a calibrated model that reproduces the field data. However, the model is not unique and multiple matching solutions exist. The objective and scope of this work is to define a workflow for constraining these solutions and obtaining a more representative model for forecasting and optimization. We used field data from a multi-pad project in the Delaware play, with actual pump schedules, frac sequence, and time delays as used in the field, for all stages and all wells. We constructed a hydraulic fracturing model using high-confidence rock properties data and calibrated the model to field stimulation treatment data varying the two model variables with highest uncertainty: tectonic strain and average leak-off coefficient, while keeping all other model variables fixed. By reducing the number of adjusting model variables for calibration, we significantly lower the potential for over-fitting. Using an ultra-fast hydraulic fracturing simulator, we solved a global optimization problem to minimize the mismatch between the ISIPs and treatment pressures measured in the field and simulated by the model, for all the stages and all wells. This workflow helps us match the dominant ISIP trends in the field data and delivers higher confidence predictions in the regional stress. However, the uncertainty in the fracture geometry is still large. We also compared these results with traditional workflows that rely on selecting representative stages for calibration to field data. Results show that our workflow defines a better global optimum that best represents the behavior of all stages on all wells, and allows us to provide higher-confidence predictions of fracturing results for subsequent pads. We then used this higher confidence model to conduct sensitivity analysis for improving the well placement in subsequent pads and compared the results of the model predictions with the actual pad results.
The aim of work is to ensure that it is possible to realize effective water injection system for low permeable reservoir with hard-to-recover deposits and an average permeability less than 1 mD. The results of oil field pilot works and computer modelling are shown and compared. The novelty of the work are rare enough field experiments in water injection system organization in low permeability reservoirs and injection system full comprehensive studding. Some empirical correlations between the values of permeability, heterogeneity, sweep efficiency and injection effectiveness for different well completion types will help reservoir engineers to select the best well pattern and to decide do we need any injection or not without labor intensive actions.
Instead of attempting to retrieve model parameters (velocity and density in the acoustic situation), Model-Independent Joint Migration Inversion tries to obtain operators, reflection and augmented transmission, the sum of transmission and wavenumber perturbation operators. However, one does not know whether the retrieved operators are correct or not without first modeling them. Thus, we model those operators for a simple model with vertical and horizontal dips only. The modeled results show that all the lateral heterogeneity is contained in the augmented transmission operator, while the reflection operator contains none of the lateral heterogeneity— only the vertical one. We then compute the critical ingredients of the inversion process, the gradients of the misfit functional. The gradients exhibit overall resemblance to those ideal operators, but less resemblance was exhibited by the augmented transmission operators and their ideal counterparts. While the resulting gradients seem promising, most of the remaining challenge would be in producing effective regularization of the augmented transmission operator.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 211A (Anaheim Convention Center)
Presentation Type: Oral
Miley, E. S. (NTC NIS-Naftagas, Serbia, Novi Sad) | Tugarova, M. A. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Belozerov, B. V. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Pilipenko, M. A. (NTC NIS-Naftagas, Serbia, Novi Sad)
The PDF file of this paper is in Russian.
The present study describes approaches for geological modeling applied on complex reservoir rocks formed by metamorphic processes on example of field located in Serbia, Pannonian basin. Key objectives are identification of productive intervals in contact zone of crystalline basement rocks and sedimentary deposits, reliable reserves estimation and new targets proposition. At the first stage of data analysis, the quality of logging and core availability was graded, which allowed to develop a strategy for working with data of varying degrees of representativeness. The algorithm of typing and correlation basement rocks is described taking into consideration different well log quality, volume and core recovery in the target interval. On wells with sufficient set of data, the concept of the reservoir formation mechanism and its structure was elaborated, and secondary data was used to confirm the model. As a result of detailed material-genetic analysis of core the core-typing matrix has been developed. This matrix allowed us to determine vertical heterogeneity of rocks. Five main objects with different rock properties have been defined: crystalline schists - basement rocks, breccias are divided into three types based on formation mechanism and cap rocks - marls. Maps that describe lateral heterogeneity were used as a basis for block field’s structure. Lateral heterogeneity of rocks composition and seismic interpretation results has been juxtaposed. The proposed mechanism of deposition formation has been confirmed. These results formed the basis of 3D geological model. Previously, reserves estimation of the reservoirs related to basement rocks was carried out assuming average parameters of all layers. After a comprehensive analysis was done the detail geological model with block structure become the main tool for decision making process.
В статье представлены подходы к построению геологической модели сложнопостроенных залежей в метаморфизованных породах фундамента на примере месторождения Паннонского бассейна на территории Сербии. Основная цель моделирования – выделение продуктивных интервалов в зоне контакта пород кристаллического фундамента и осадочного чехла, достоверная оценка запасов углеводородов и поиск перспективных для бурения участков. В рамках первичного анализа проведена классификация качества каротажных и керновых данных. Это позволило выработать стратегию работы с информацией разной степени репрезентативности. Алгоритм типизации и корреляции пород фундамента описан с учетом различных качества материалов геофизических исследований скважин, объема и выноса керна в целевом интервале. На скважинах с достаточным набором данных прорабатывалась концепция механизма формирования залежей и их структура, а второстепенные данные использовались для подтверждения или опровержения модели. По результатам детального вещественно-генетического анализа керна разработана матрица типизации керна, на основании которой установлена вертикальная неоднородность. Определены пять основных объектов с различными фильтрационно-емкостными свойствами: кристаллические сланцы отнесены к породам фундамента, брекчии разделены на три типа по механизму образования, выделены также породы-покрышки – мергели. Карты, описывающие изменение состава пород по площади, послужили основой для выявления блокового строения месторождения. При сопоставлении результатов интерпретации сейсмических данных с латеральной неоднородностью подтвержден предложенный механизм формирования отложений, который взят за основу при создании трехмерной геологической модели. Ранее оценка запасов по залежам в фундаменте выполнялась по усредненным характеристикам всех пластов, после проведения комплексного анализа основным инструментом для принятия решений стала детальная геологическая модель пластов с блоковым строением.
We develop a general framework for computing reflection traveltime derivatives with respect to offset in layered anisotropic media with weak lateral heterogeneities from curved interfaces and smoothly variable velocities. We specify the expression for the second-order derivative related to normal moveout (NMO) velocity and show that it is influenced by both types of heterogeneities. In general layered media, the effects get accumulated along the raypath from the source to the receiver and can be computed using the proposed recursive relationship. Numerical examples show that taking into account heterogeneities can lead to more accurate moveout approximations and therefore, aid in analysis of estimated NMO velocities in practice.
Presentation Date: Monday, September 25, 2017
Start Time: 2:40 PM
Location: Exhibit Hall C/D
Presentation Type: POSTER
Abstract Unconventional reservoirs can have significant vertical and horizontal heterogeneity in the formation. It is important to understand these spatial changes, whether they are mineralogical or structural. Open natural fractures contribute significantly to production in these reservoirs. The challenge is how to accurately identify the open natural fractures to help optimize completion strategy and improve production. In this paper we show how advanced surface mud logging techniques help identify open natural fractures and structural faults from detection of light gases like helium and methane while drilling. These techniques are validated by correlating with new generation oil-based image logs. In recent years, significant improvements are seen in surface logging techniques from analyzing mud gas and drill cuttings. These improvements have led to new sophisticated methodologies to petrophysically and geochemically characterize the reservoir rocks and the production fluids. Early characterization of these reservoir properties adds significant value in optimizing drilling and designing completions. Sophisticated surface logging technologies can now provide a more cost-effective solution to reservoir characterization when compared to running more expensive downhole logging tools. Correlating the reservoir rock properties from geochemical composition of the rock to evaluate heterogeneity along the lateral length is achieved using advanced mud-gas evaluation methods. Which include net mud gas measurement, stable carbon isotopic ratios, and elemental spectroscopy using the X-Ray Fluorescence (XRF) technique. Besides the primary aspect of fracture identification other measurements like identifying drill bit metamorphism by detecting alkene hydrocarbons in drilling fluid can help optimize the drilling performance and prevent drill bit failures. Introduction Several unconventional resource plays have been explored, exploited and developed in North America in the recent years. Several technologies related to open-hole or cased-hole log evaluation have been tested and developed successfully over the years. However, these tools can be expensive to run routinely on all new wells for evaluation purposes. With proper calibration, advanced surface logging methods can be an effective low-cost alternative for formation evaluation. Measurement-While-Drilling (MWD) Gamma Ray (GR) log is typically used while drilling in most horizontal wells to help identify vertical and lateral reservoir heterogeneity, picking formation tops and identifying stratigraphic layers. However there remains a need for a more comprehensive evaluation of the reservoir rock and fluid properties to help drill, complete and produce the wells effectively.
Nazerali, N. A. (MIT) | Coles, D.A. (Schlumberger Doll Research) | Minsley, B. (USGS) | Mukhopadhyay, A. (Kuwait Institute of Scientific Research) | Al-Ruwaih, F. (Kuwait University) | Morgan, F.D. (MIT)
Aquifer storage and recovery (ASR) is a viable means of enhancing the water storage capacity of Kuwait, enabling sustainable water management options such as the storage of wastewater treated to tertiary levels. For the purpose of a baseline geophysical survey to characterize the Dammam Formation in the Kabd well field, which is a target aquifer for a pilot ASR project, one dimensional (1D) resistivity imaging (vertical electrical sounding) was conducted using the D.C. resistivity (DCR) and transient electromagnetic (TEM) methods.
For DCR, we implement a systematic approach to obtain a robust 1D cross section using both fixed-thickness layer and variable-thickness layer inverse modeling techniques in sequence. The optimal model has 6 layers above the halfspace depth of 101 m, consisting of 3 surface layers down to 15 m depth and 3 intermediate layers, which likely correspond to the formations of the Kuwait Group, which overly the Dammam Formation. Anomalies in the data which cannot be attributed to noise or error are not adequately fit by the best set of models. The possibility that lateral heterogeneity explains the variation in the data is explored using approximate 2D resistivity inverse modeling. Such heterogeneity may be explained by the occurrence of gatch (caliche) in the Fars and Ghar formations of the Kuwait Group.
The comparison between DCR and TEM indicates that the TEM data is not sensitive to a relatively resistive layer that is resolved by the 1D DCR inversion, or to the resistive heterogeneities that are indicated in the approximate 2D DCR inverse images. We obtain the top of the Dammam formation – or the aquitard on top of the Dammam – as the model half-space depth at approximately 100 m below the surface in both data sets.
We compare the 1D cross section taken at the center of the approximate 2D image, which accounts for heterogeneity, and the simple 1D layered model. With careful parameterization in the approximate 2D inversion, we have assured that the two cross sections approximately match each other, showing that the 1D interpretation in this case may be slightly erroneous but does not lead to wrong conclusions to the specific target questions addressed by the experiment. Our recommendation is therefore to use DC Resistivity in preference over TEM, and also to use 3D/2D whenever possible. However, use of 1D DCR remains approximately accurate.
The simulation of a zero-offset section leads to a first interpretable time image and is still one of the key processing steps in seismic imaging. While recent works have indicated that common-offset stacking results in improved resolution and illumination in complex settings, the zero-offset approximations are still reasonably accurate, especially when lateral heterogeneity is moderate. Due to the increased dimensionality of the problem, the common-offset stack is computationally expensive, though. The partial common-reflection-surface stack uses local subsets of globally defined zero-offset operators to perform common-offset stacks. In this work, we suggest an extension of this scheme, in which not only travel times but also slope information is extracted from the zero-offset surfaces. We show, with simple synthetics and for a complex field data example from the eastern Mediterranean, that the presented method allows for efficient full prestack slope analysis and refinement, which can help to further automate the picking-intensive process of stereotomography.
The 2D common-reflection-surface (CRS) stack is a multiparameter extension of the classical CMP method (Mayne, 1962). It was formulated for a zero-offset (ZO, Jäger et al., 2001) and for an arbitrary common-offset (CO) central ray (Zhang et al., 2001; Höcht et al., 2009). While the ZO approximation is fast and reasonably accurate for moderate lateral heterogeneity, the CO counterpart shows its strengths in complex settings, providing improved resolution and illumination at the cost of higher computational expenses (see, e.g., Spinner et al., 2012).
In most implementations of the CRS stack, events are described by a hyperbolic operator (Schleicher et al., 1993; Jäger et al., 2001), which, for moderate reflector curvature and comparably weak lateral heterogeneity can lead to high accuracy over a wide range of offsets and midpoints. Based on this assumption of globality, the partial CRS stack introduced by Baykulov and Gajewski (2009) utilizes CO subsets of ZO CRS operators for efficient prestack data enhancement, interpolation and regularization (e. g., Eisenberg-Klein et al., 2008).
In this work, we seek to extend the approach of partial CRS by not only extracting local traveltimes but also slope information from the estimated ZO operators. Based on the work by Lavaud et al. (2004) we suggest a simple scheme, in which the extracted slopes, i. e., first-order coefficients are used to perform a CO stack. We show, with simple synthetics and a complex field data example, that the presented method, due to its formulation in terms of CO attributes, allows for efficient coherence-based local refinement, whose output may directly be used in prestack slope-based stereotomography (Billette and Lambaré, 1998). In the following section, we briefly review the basics of the CRS method and formulate the theoretical framework of the suggested approach.
The evaluation of the soil stiffness is routinely performed by direct investigation, using geotechnical tests such as CPT-CPTu. A low cost complement to the direct investigation would be the use of seismic surface wave methods such as, for example, the “Spectral Analysis of Surface Waves” (SASW) or the more updated “Multichannel Analysis of Surface Waves” (MASW) which use the dispersive nature of surface waves to retrieve the shear velocity (Vs) profile of the subsurface. Unfortunately, available inversion algorithms assume the subsurface model as a stack of homogeneous parallel layers hence of limited practical use when subsoil is known to be laterally heterogeneous. In the following, we shall introduce a novel strategy based on the Direct Interpretation of Phase Lags (DIPL) among pairs of seismic signals, based on a combination of SASW and MASW work-flows, which aims to retrieve the 2-D Vs subsurface profile and in particular to tackle the lateral heterogeneity issue. As an example of application we shall retrieve the 2-D VsS/sub> profiles before and after a Jet-Grouting (JG) intervention performed at a test site studied in the context of the reconstruction and prevention phase following the seismic sequence that struck the Emilia Region (Northern Italy) in 2012. Soil stiffening due to the cement mixture injection is then retrieved in term of Vs increase.
The evaluation of the soil stiffness is routinely performed by direct investigation, using geotechnical tests such as CPT-CPTu. Even if this approach gives detailed and reliable information, the result is only valid point wise and the economic impact of a survey quickly grows when a dense sampling has to be undertaken over vast areas. A low cost complement to the direct investigation would be the use of SASW, (Nazarian and Stokoe, 1984) or the more updated MASW method, (e.g. Gabriels, 1987; Tokimatsu, 1995; Tselentis and Delis, 1998; Park et al., 1999, Socco and Strobbia, 2004), which use the dispersive nature of surface waves excited by an active source and recorded by a linear array of receiver deployed on the ground to retrieve the shear velocity profile of the subsurface. The propagation of SW along the array allows for the construction of a dispersion pattern, which is retrieved by transforming the acquired seismograms from the timespace domain to a more suitable domain, typically, the frequency-Rayleigh wave velocity (f-VR) domain. In the SASW method the dispersion is represented by a set of points (f,VR), while in the MASW the data are transformed either using the f-k or the τ-p (McMechan and Yedlin, 1981) and finally expressed as an f-VR power spectrum. The spectral maxima are then automatically picked to form the so-called dispersion curve.
Abstract Unconventional shale-gas reservoirs are usually highly laminated with vertical and lateral heterogeneity. The elastic mechanical properties are highly anisotropic along the different orientations parallel and perpendicular to the bedding. The formation heterogeneity, elastic anisotropy, and structural complexity affect the stress field both near and far from the wellbore and thus the fracture containment, fracture initiation pressure, and breakdown pressure. A better understanding of the formation properties and in-situ stress can be achieved by an advanced logging program. Many studies have shown improved production in the lateral wells by implementing an engineered completion design using advanced sonic logs and other high-tier logs. The importance of understanding these properties in the lateral wells also raised questions including whether we can predict lateral log responses from pilot wells and whether the formation is laterally homogenous. In this study, we compared the projected lateral logs from pilot wells with the actual lateral logs to shed insights on the important question of formation heterogeneity. Different techniques were applied including a gamma ray method and an advanced 3D near-well structural model. The 3D model took advantage of the valuable information from borehole geology interpretation of image logs such as bedding, fractures, and faults to build high-resolution near-well structures. It was then used as a framework to model the reservoir properties and far-field stress using methods including a layer-cake and a finite-element approach. The output of the model showed the lateral heterogeneity of the reservoir by comparing the lateral section with the pilot well. The reservoir properties from these techniques described above were then incorporated and evaluated as part of the completion design workflow, which focused on both near-wellbore and far-field modeling. The results showed the benefits and limitations of each propagating modeling technique for optimizing the completion design and shed light on the realization of being able to project the pilot logs across a single horizontal well or an entire pad.