Agnihotri, Praveen (ADNOC Onshore) | Pandey, Vikram (ADNOC Onshore) | Thakur, Parmanand (ADNOC Onshore) | Al Mansoori, Maisoon (ADNOC Onshore) | Rebelle, Michel (Total SA) | Smith, Steve (Baker Hughes, a GE Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Zhunussova, Gulzira (Baker Hughes, a GE Company) | Hassan, Syed (Baker Hughes, a GE Company)
Holistic assessment of project economics and subsurface characterization provides a framework to handle challenging reservoirs. Capturing ranked uncertainties based on their impact on the project and meticulous working towards de-risking the project is key for the success of the entire project. Committing increased production from the field is dependent on proper evaluation of the reservoir.
This paper reviews characterization of a tight reservoir deposited in the intra-shelf Bab basin during lower Aptian time. Initial stage reservoir characterization is critical in formulating reservoir development plan and estimating a realistic assessment of rates and volumes for the field.
The target formation is a low-permeability (average permeability 0.5 mD) heterogeneous carbonate reservoir sitting directly above and adjacent to a producing carbonate reservoir. It is essential to understand communication between the zones. The pilot well is drilled with 225 ft of conventional core and quad-combo logs. Advanced logs such as resistivity image, cross-dipole acoustic, nuclear magnetic resonance, vertical interference test (VIT), formation pressure (including pressure transient data), and fluid samples were acquired. The main objectives of the evaluation program were to determine the formation pressure, collect representative oil sample(s), conduct vertical interference tests between the sub-zones and collect appropriate data for geomechanical and rock-physics characterization.
Thorough pre-job planning and cross-discipline cooperation during the operation provided high fidelity log data and interpretation of the data into a coherent result. This included integration of image data with vertical interference tests from the wireline formation tester (WFT) where barriers were confirmed. In addition, NMR permeability was matched and calibrated using pretest mobility measurements and formation pressure data was combined with full waveform advanced acoustic processing to explain the communication between the upper target zone and the lower producing reservoir. Advanced acoustic analysis helped to fully characterize the target formations with stoneley permeability, azimuthal anisotropy, and presence of fractures.
This paper demonstrates the importance of multi-disciplinary team effort in characterization of challenging reservoirs. It highlights the importance of holistic planning before the execution phase, and keeping a focus on the larger goal while executing individual aspect of a complicated project.
Formation evaluation measurements have evolved over decades and occasionally it benefits the industry to provide a review of how the latest logging measurements fit together in an integrated manner, for successful evaluation of a challenging reservoir.
Newby, Warren (Total SA) | Abbassi, Soumaya (Total SA) | Fialips, Claire (Total SA) | D.M. Gauthier, Bertrand (Total SA) | Padin, Anton (Total SA) | Pourpak, Hamid (Total SA) | Taubert, Samuel (Total SA)
The Upper Jurassic (Oxfordian to Late Kimmeridgian) Diyab Formation has served as the source rock for several world-class oil and gas fields in the Middle East. More recently it has become an emerging unconventional exploration target in United Arab Emirates (UAE), Saudi Arabia, Bahrain and its ageequivalent Najhma shale member in Kuwait. The Diyab is unique in comparison to other shale plays due to its significant carbonate mineralogy, low porosities, and high pore pressures. Average measured porosities in the Diyab are generally low and the highest porosity intervals are found to be directly linked to organic porosity created by thermal maturation. Despite low overall porosities, the high carbonate and very low clay content defines an extremely brittle target, conducive to hydraulic fracture stimulation. This coupled with a high-pressure gradient facilitates a new unconventional gas exploration target in the Middle East. However, these favorable reservoir conditions come along with some challenges, including complex geomechanical properties, a challenging stress regime and the uncertainty of whether the presence of natural fractures could enhance or hinder production after hydraulic fracture treatment. Only recently has the Diyab been studied in detail in the context of an unconventional reservoir. This paper presents an integrated approach allowing a multidisciplinary characterisation of this emerging unconventional carbonate reservoir in order to gain a better understanding on the plays' productivity controls that will aid in designing and completing future wells, but already encouraging results have been observed to date.
Manivannan, Sivaprasath (Ecole Polytechnique) | Bérest, Pierre (Ecole Polytechnique) | Jacques, Antoine (Total SA) | Brouard, Benoît (Brouard Consulting) | Jaffrezic, Vincent (Total SA) | De Greef, Vincent (Ecole Polytechnique)
In wells producing water, oil, gas or geothermal energy, or in access wells to hydrocarbon storages, it is critical to evaluate the permeability of the formation as a function of depth. Continuous permeability logs in these wells are typically derived using tools that measure electrical, nuclear, magnetic or acoustic signals, using empirical relations that are often formation dependent. The permeability logs derived using these empirical relations often show significant differences when compared to the permeabilities obtained from core samples or well tests.
A new technique is proposed in this paper in which the open hole is scanned with an interface between two fluids with a large viscosity contrast. The injection rate into the formation depends on interface location and well pressure history. An inverse problem is solved to estimate permeability as a function of depth from the evolution of flow rates with time. During the test, the well is equipped with a central tube, typically a drill string, and the scanning is done by injecting in the central tube a liquid that is different from the liquid in the annulus, at a constant wellhead pressure. Injection and withdrawal rates are measured at the tubing and the annulus wellheads, respectively; the difference between these two rates gives the formation injection rate. Interface location is also estimated from the flow rates and pressure at the wellhead and an injection profile in the open hole is derived.
A permeability log is derived from this injection log by considering a radial, monophasic flow in each layer and same skin value for all formation layers. Initial formation pressure and storativity, estimated from other logs, are also used as inputs. The sensitivity of the permeability log to these inputs is estimated using analytical expressions. The proposed methodology is applicable to oil or water bearing formations drilled using oil or water-based muds, respectively.
A continuous permeability log is estimated from the synthetic test data using the proposed interpretation workflow; it shows a correlation of 0.95 (on a scale of 0 to 1) when compared to the input permeability log. A laboratory model that mimics a multi-layered formation is used to study the repeatability of the technique and the validity of the uniform skin assumption by creating a mudcake at the inner radius. Four consecutive tests were performed on the same set of samples and the interpreted permeability logs are compared to the benchmark permeability log; correlations are greater than 0.94.
This paper uses pseudo-time to extend the application of constrained multiwell deconvolution algorithm to gas reservoirs with significant pressure depletion. Multiwell deconvolution is the extension of single well deconvolution to multiple interfering wells. Constraints are added to account for a-priori knowledge on the expected deconvolved derivative behaviors and to eliminate non-physical solutions.
Multiwell deconvolution converts pressure and rate histories from interfering wells into constant-rate pressure responses for each well as if it were producing alone in the reservoir. It also extracts the interference responses observed at each of the other wells due to this single well production. The deconvolved responses have the same duration as the pressure history. This allows to identify reservoir features not visible during individual build ups.
Deconvolution techniques can only be applied to pressure and rate data when flow can be represented by linear equations. In strongly depleted gas reservoirs, fluid properties, and gas compressibility in particular, are pressure dependent, which makes the flow problem non-linear. The paper uses pseudo-pressure and pseudo-time transforms to linearize the problem in such conditions.
The pseudo-time method developed by
The paper extends the application of constrained multiwell deconvolution to strongly depleted gas reservoirs. Constrained multiwell deconvolution is an efficient way to exploit data recorded by permanent downhole pressure gauges and provides information not otherwise available. It can help to identify field heterogeneities and compartmentalization early in field life, making it possible to modify the field development plan and to improve locations of future wells. It can accelerate history-matching with the reservoir model by doing it on the constant rate pressure responses rather than on the actual, usually complex, production history. An added advantage is that comparison between the pressure derivatives of the model and the actual deconvolved derivatives allows identification of mismatch causes.
The success of an unconventional hydrocarbon development depends on effective hydraulic fracturing, which highly depends on reservoir properties and the stimulation procedure. In the beginning of shale development, the industry practice was to conduct a large number of field trials, which was a very expensive and time consuming practice. Advanced integrated studies are being performed today by industry on rock and SRV (Stimulated Rock Volume) characterization, however the topic remains still vastly challenging, due to the complex nature of fracturing in shales as well as because of the complexity of multiple physics and the number of operational parameters involved in shale development from formation characterization to SRV creation and production.
This project used a numerical simulation approach, based on truly 3D reservoir modelling of fracture network generation and stimulation, to optimize hydrocarbon production through the investigation of a large number of virtual well stimulations. Starting with a calibration workflow, taking into account potential reservoir and geomechanical uncertainties, a calibrated reservoir model was built. The goal of this approach is to find the optimal stimulation parameters much faster with much less investments compared to the industry standard of simply undertaking a trial and error well drilling and completion process. The reservoir model calibration, the multi-realization runs, together with the metamodel analyses have been performed using a workflow and a range of advanced software tools developed since 2010 (Bai et al, 2011, Gao et al, 2011, Yeh et al, 2018).
In this study, the proposed workflow was applied to a major Unconventional Oil and Gas field. A multi-stage hydraulic fracturing operation has been modelled and calibrated based on the data from a real hydraulic fracture shale gas operation. Geomechanical and geological uncertainties have been taken into account in the calibration process of the reservoir model. Furthermore, microseismic monitoring results and fracture treatment pressure data have been used to calibrate important parameters in the fracturing modelling process. Utilization of multi-realization runs while scanning parameters uncertainties, enabled to rank the parameters influencing the stimulated rock creation process.
In a second step, a sensitivity study has been performed within a predefined window of variation of operational parameters. From this sensitivity study, important operational parameters influencing fracture network geometry and related hydrocarbon production have been identified. Based on the sensitivity study, meta models were then generated which represent the influence of the variation of operational parameters on fracture network geometry and hydrocarbon production. The meta models have been combined with costs to optimize operational parameter taking into account the conflicting nature of EUR, NPV, VIR. The results of this meta model-based optimization may help improve the decision-making process of hydraulic fracturing operations and shale play development, including unit development costs and unit profitability.
Water and gas permeability of fractures with or without proppants under in situ effective stress conditions is a key input parameter for numerical modelling of Stimulated Rock Volume (SRV) and optimization of proppants recipe used in hydraulic stimulation jobs for gas/oil shale reservoirs. This paper presents the experimental results of fracture permeability tests carried out on the Vaca Muerta shale, with and without proppants. Permeability tests are carried out according to a specific protocol simulating the change of in situ effective stress due to production. After creating a fracture in shear mode in the triaxial cell, the gas permeability was measured twice with a measurement of the water permeability between. Subsequently, the fracture was filled with the same proppants as used in the field. The mechanical closure and change of hydraulic opening of the fracture with different concentrations of proppants were then measured under cyclical effective stress. The evolution of fracture permeability is then compared with the mechanical closure recorded by an extensometer. This experiment is used to investigate the effect of proppant concentration on permeability evolution under varying effective stress. The experimental results presented in this paper can be used as input data for numerical modelling of fractured shale gas reservoirs and for optimization of proppant concentration in hydraulic stimulation jobs.
The potential of gas production is first and foremost determined by geochemical and petrophysical factors such as total organic carbon content, thermal maturity, porosity and permeability. However, the productivity is strongly dependent on the fracture network's connectivity and conductivity (including both hydraulic fractures and activated natural fractures) since the shale matrix has extremely low permeability. Numerous geomechanical parameters of shale control the hydraulic quality of stimulated reservoir volume (SRV) created by hydraulic stimulation: elasticity and its variability, strength with regards to tensile and shear failure as well as fracture propagation, filling material of natural fractures/joints and the permeability before and after stimulation (Su K et al. 2014).
This work develops a method of stress inversion for a geometrically complex catalogue of microseismic events in a non-stationary stress field. We first use the k-means algorithm to split the data into suitably sized groups containing between Nmin < Ngroup < 2Nmin events. The centroids of these groups are then considered as the nodes of an unstructured grid, and we simultaneously solve for the stress state in each group using damped inversion. To account for the irregularity of the unstructured grid, we use the reciprocal square distance 1/r2 as weights between nodes, as opposed to the existing method where a weight of 1 is assigned between adjacent nodes on a regular grid. Focal planes are selected from the auxiliary plane using the fault instability criterion.
The method is applied to microseismic data from an unconventional shale play in the Vaca Muerta formation in Argentina, where results suggest the presence of a pre-existing strike-slip faulting stress regime. We also find that the unambiguous focal plane picks suggest the apparent dip-slip focal mechanisms are indeed dip-slip movement along sub-vertical natural fractures, which correlate well with image log data. We suggest that these dip-slip events are caused by shear stress induced by the opening of the hydraulic fractures.
The notion that observed fault planes are related to the local stress field dates back to Anderson (1905, 1951), who proposed that the stress-slip, normal, and reverse faulting regimes are dependent on the orientation of the three principal stresses. Wallace (1951) and Bott (1959) then proposed that the slip vector is parallel to the tangential shear traction on the fault. Following this, Michael (1984), Gephart and Forsyth (1984), and Angelier (2002) developed commonly used methods to solve for the stress tensor given a set of focal mechanisms. Specifically, these methods solve for the directions of the three principal stresses, and the stress ratio R = (σ1 – σ2)/(σ1 – σ3). In each case, only the direction of slip is considered, and so one can only solve for the deviatoric stress tensor, i.e. trace(σ) = 0. Modifications suggested by Lund and Slunga (1999), and Vavryčuk (2014) allow one to select the focal plane from the conjugate nodal plane pair by applying the Mohr-Coulomb failure criterion to each nodal plane, which returns the friction coefficient μ as an additional output.
Drilling multiple horizontal wells from a single pad has become a common approach in many shale plays in response to the economic, real estate, water management, regulations challenges the operators face while developing such plays. The challenge of optimizing the landing zones of those wells depends, in part, on the knowledge of the Stimulated Rock Volume (SRV) created during the fracturing jobs and the ability to predict its evolution during production. The objective of this work is to show how to get this understanding through a multidisciplinary workflow and how this helps to optimize a multi-landing zone development in a field case in Vaca Muerta.
The first part of this work presents a sensitivity study in a single-well, focusing on the key geological and geomechanical factors with ranges based on data collected from well logs and field observations. These include characteristics of the natural fracture network, facies, laminations, variations on petroelastic properties and principal stresses, and anisotropy. The impact of these parameters upon the geometry of the SRV and well productivity is presented using pseudo-3D fracture model and fluid flow-geomechanics simulation coupling technique. Once the key parameters affecting SRV geometry and productivity are determined, the second part of this work shows the results of multi realization (multiple scenarios and well landings) on green and brown field stimulations.
Analysis of the SRV geometry under undepleted and depleted conditions suggests that the stress change associated to production does impact the overall SRV generation and must be considered for multi-well multi-layer strategy. Horizontal Stress Anisotropy, preexisting fractures and laminations are the static properties which have the most important control on the Stimulate Rock Volume (SRV) dimensions and complexity. The SRV is dynamic, changes during time. Addressing these changes allows us to better plan a multi-landing zone design (sequence, landing depth, well spacing, etc.) at a given period of time for this field case. The presented work goes beyond an ordinary investigation of SRV creation driving properties: it allows for a better understanding of uncertainties related to these properties and ultimately depicts the static and dynamic impact on production in order to guide the optimization of well placement on the field case development.
Production optimization while reducing data acquisition costs is a key factor in successful development of unconventional plays. Completion strategies in such plays typically involve geometrical approaches that ignore subsurface heterogeneities. Cost-effective subsurface data acquisition techniques are needed to design more effective completion strategies and to close the loop through production evaluation of the engineered fractures.
A new formation evaluation technique was performed 1) in the open hole of a horizontal shale gas well and 2) in the cased hole of the same well post fracking. This technique combines the principles of well testing and logging, and all measurements are made at the surface. In an open hole, it provides a continuous injectivity index profile from which better-producing zones can be identified and in which the hydraulic fracturing strategy can be optimized. When running post -fracturation, it provides injectivity of each cluster and enables identification of successfully fracked clusters.
An open hole test was performed with the well still equipped with the drill pipe. A batch of base oil, less viscous than drilling mud, is circulated continuously. The two liquids, base oil and drilling mud, were separated by a viscous spacer. The annulus wellhead pressure was increased to impose an overhead pressure at formation depth. Because the wellbore pressure is almost constant, the difference between the wellhead flow rates at the inlet in the drill pipe and at the outlet in the annulus provides the total injection rate into the formation. This formation injection rate changes as the less-viscous liquid passes through the open hole due to the viscosity contrast between the two liquids. An injectivity profile is derived from the wellhead flow rates.
Two runs were performed in the same open hole complying with HSE drilling rules and without any well integrity issues at the casing shoe. The observed variations in formation injectivity were consistent between the two runs and the injectivity logs showed strong correlations to gamma ray (GR) and mineralogy logs. The 1500-m long lateral section of the open hole was tested in less than 30 minutes, demonstrating the potential of the method to be industrialized at a low cost.
This paper applies a new constrained multiwell deconvolution algorithm to two field cases: a gas reservoir with two producers, and an oil reservoir with three producers and one injector. Responses given by the constrained multiwell deconvolution are compared with simulations from history-matched reservoir models.
Permanent downhole pressure gauges are routinely installed in most new wells. The resulting large datasets are usually underexploited, however, because it is near impossible to extract information with conventional techniques in the case of well interferences. Multiwell deconvolution (
The published multiwell deconvolution algorithms are extensions of the single-well deconvolution algorithm from von Schroeter
By extracting well and interwell reservoir signatures, multiwell deconvolution allow identification of compartmentalization or unanticipated heterogeneities very early in field life, making it possible to adjust the field development plan and the locations of future wells. In addition, it can accelerate the history-matching process by doing it on constant rate pressure responses rather than on complex production histories. An added advantage is that the comparison between the model derivatives and the actual deconvolved derivatives enables identification of mismatch causes.