Kallesten, Emanuela (University of Stavanger) | Østebø Andersen, Pål (The National IOR Centre of Norway) | Berawala, Dhruvit Satishchandra (University of Stavanger) | Korsnes, Reidar Inge (The National IOR Centre of Norway) | Vadla Madland, Merete (University of Stavanger) | Omdal, Edvard (The National IOR Centre of Norway) | Zimmermann, Udo (University of Stavanger)
Understanding the impact of typical water-related IOR techniques is fundamental to the development of chalk reservoirs on the Norwegian Continental Shelf (NCS). We investigate the contribution and interplay of key parameters influencing the reservoir's flow and storativity properties such as effective stresses, injecting fluid chemistry and geomechanical deformation. This is done by developing a mathematical model which is applied to systematically interpret experimental data. The gained understanding is useful for improved prediction of permeability development during field life.
The model we present is for a fracture chalk core where fluids can flow through the matrix and fracture domains in parallell. The core is subject to a constant effective stress above yield resulting in time-dependent compaction (creep) of the matrix, while the fracture does not compact. Reactive brine injection causes enhanced compaction, but also permeability alteration. This again causes a redistribution of injected flow between the two domains.
A previous version of the model parameterizing the relation between chemistry and compaction is here extended to quantify the impact on permeability and see the impact of flow in a fracture-matrix geometry. A vast set of experimental data was used to quantify the relations in the model and demonstrate its usefulness to interpret experimental data. Two outcrop chalk types (Aalborg and Liege) being tested at 130 °C and various concentrations of Ca-Mg-Na-Cl brines are considered. However, assumptions were required especially regarding the fractures behavior since directly representative data were not available.
The tests with inert injecting brine were used to quantify the impact of matrix and fracture mechanical compaction on permeability trends. To be able to explain the tests with reactive brine, an important finding is that permeability not only decreased due to enhanced porosity reduction, but also because of a quantifiable chemistry related process (dissolution-precipitation).
Sensitivity analyses were performed regarding varying fracture width, injection rate and chemistry concentration to evaluate the impact on chemical creep compaction and permeability evolution in fractured cores. The model can be used to highlight parameters with great influence on the experimental results. An accurate quantification of such parameters will contribute to refining lab experiments and will provide valuable data for upscaling and field application.
This paper attempts to answer a fundamental question pertinent to fracture characterization of unconventional basement reserves using rock mechanics & petrophysics; are open fractures in basements necessary critically stressed? Evaluation of naturally occurring fractures are critical for production as well as reserves estimation. In this regard, a study well was drilled in the basement section of the Cauvery basin to explore unconventional pay zones & characterize the contributing fractures by integrated Geomechanical & Petrophysical analysis.
A suite of open hole logs including the basic, acoustic and electrical borehole images were acquired and an integrated approach was taken, including geomechanical analysis to identify the contributing fractures. Standard petrophysical evaluation in basements was inconclusive and porosity quantification from fractures posed a major challenge. Image log analysis involved identification of conductive and resistive fractures in the gauged wellbore and combining Stoneley reflectivity further indicated probable open fractures. Following this, a geomechanical analysis was carried out to determine the current in-situ stress orientation/magnitudes based on observed breakouts. Finally a CSF study was done to check for fracture slip events.
Based on the integrated study of Petrophysics and Geomechanics, an optimized workflow was developed and the critically stressed fractures were identified. It was found that, while some fractures strike direction was different from the present day maximum horizontal stress direction (SHmax), in general, most fractures were indeed aligned to SHmax. To check the fluid flowing capability of fracture networks, formation tester was deployed in selective zones for testing and sampling. Successful hydrocarbon sampling from selective fractures with orientation not aligned to SHmax led to the validation of the current study. The results proved that while most critically stressed/open fractures did indeed contribute to flow, a smaller fraction of the naturally occurring fractures while contributing to flow, were not necessarily aligned to the in situ orientations.
The results present a discrepancy between observation and the expectation that open fractures are necessarily oriented parallel or nearly parallel to modern-day SHmax. This works highlights the fact that although paleo-stresses may influence the fracture networks, it is the contemporary in-situ stresses that truly dominate fluid flow and only through a detailed understanding of the critically stressed areas, can we come to a decisive conclusion that further improves overall recovery.
Al-Enezi, Badriya (Kuwait Oil Company) | Liu, Peiwu (Schlumberger) | Liu, Hai (Schlumberger) | Kanneganti, Kousic Theja (Schlumberger) | Aloun, Samir (Kuwait Oil Company) | Al-Harbi, Sultan (Kuwait Oil Company) | Al-Ibrahim, Abdullah (Kuwait Oil Company)
A recent study showed that Tuba reservoir, a limestone-rich formation, has the highest oil in-place of all upcoming reservoirs in North Kuwait. This tight formation has three main layers - Tuba Upper (TU), Tuba Middle (TM), and Tuba Lower (TL) with several reservoir units alternating with non-pay intervals. The reservoir units contain significant proven oil reserves; however, production performance after conventional acid fracturing treatments has been historically subpar. As part of new development plan, two horizontal wells, one in TU and one in TL were drilled to evaluate the production potential of a new completion strategy and technologies.
This paper presents one such technology, a single-phase retarded acid system used as a pilot project study. In contrast with previous conventional emulsified acid systems, the single-phase retarded acid minimized tubing friction, thus enabling high pumping rates for the entire treatment. Alternating with the acid system, a viscoelastic surfactant-based leakoff control fluid system allowed the acid stages to reach deeper into the formation. To aid, degradable fiber technology was pumped in several stages to achieve near-wellbore diversion and further control leakoff into large natural fractures, thus improving the stimulated reservoir volume. These fibers are designed to completely degrade with time and temperature after the treatment. Delivery of the complex acid fracturing treatment was optimized in real time for each stage based on bottomhole pressure trend and response.
Combining a new single-phase retarded acid system with chemical diversion technology has proved to be effective in maximizing lateral coverage and etched fracture half-length. Post-treatment evaluation of TU horizontal well revealed the initial production was as much as 150% higher than offset vertical wells after conventional treatments with gelled acid and as high as 100% higher than a previous multistage horizontal well treated with emulsified acid. The TL horizontal well was just put into production recently and is showing encouraging results considering the lower reservoir quality compared to TU formation.
The success of this technique and technical combination delivered breakthrough results for this region and has engaged new interest in developing the Tuba reservoir.
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.
Al-Nakhli, Ayman (Saudi Aramco) | Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Al-Shehri, Dhafer (King Fahd University of Petroleum and Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum and Minerals)
Recent rise in global warming and fluctuations in world economy needs the best engineering designs to extract hydrocarbons from unconventional resources. Unconventional resources mostly found in over-pressured and deep formations, where the host rock has very high strength and integrity. Fracturing techniques becomes very challenging when implemented in these types of rocks, and in many cases approached to the maximum operational limits without generating any fracture. This leaves a small operational window to initiate and place the hydraulic fractures. Current stimulation methods to fracture these formations involve with adverse environmental effects and high costs due to the entailment of water mixed with huge volumes of chemicals such as biocides, scale inhibitors, polymers, friction reducers, rheology modifiers, corrosion inhibitors, and many more.
In this study, a novel environmentally friendly approach to reduce the breakdown pressure of the unconventional rock is presented. The new approach makes it possible to fracture the high strength rocks more economically and in more environmentally friendly way. The new method incorporates the injection of chemical free fracturing fluid in a series of cycles with a progressive increase of pressure in every cycle. This will allow stress relaxation at the fracture tip and correspondingly enough time for fracturing fluid to infiltrate deep inside the rock sample and weaken the rock matrix. As a result of which the tensile strength-ultimately the breakdown pressure of the rock gets reduced. The present study is carried out on different cement blocks.
The post treatment experimental analysis confirmed the success of cyclic fracturing treatment. The results of this study showed that the newly formulated method of cyclic injection can reduce the breakdown pressure by up to 24% of the original value. This reduction in breakdown pressure helped to overcome the operational limits in the field and makes the fracturing operation greener.
Diagnostic fracture injection tests (DFIT) are conducted to estimate the magnitude of the minimum horizontal stress (tectonic) and characterize essential reservoir properties, such as reservoir permeability and actual reservoir pressure in conventional and unconventional reservoirs. When properly designed, and conducted, this type of transient test can help operators to reliably extract important reservoir data and reduce related operational costs and time. This paper provides a state of the art sensitivity analysis based on real pressure data that describes the impact of DFIT design on reservoir parameters acquisition.
In this study, the engineering steps to optimize the design, conduct the test and interpret acquired data are examined through a sensitivity analysis to obtain reliable results. Furthermore, the interpretations of the performed tests can be combined with an enhanced image log analysis (if available) to constrain the in-situ stress conditions, including the magnitude and direction for all three principal stress components.
Multiple operational parameters, such as injection rate, injection duration, rate reduction, leak-off mechanism and fall-off duration could significantly impact the fracture extent and mechanical response of the rock, thus affecting the fluid flow regime after shut-in. Therefore, all these variables should be evaluated in the proposed methodology to optimize the test, which is the key difference between conventional design and the presented reservoir driven design. To quantify the impact of operational parameters in reservoir response and validate the proposed approach, extensive sensitivities are performed with a complete well data set from a typical unconventional play by running in-house fracture models, considering multiple testing parameters (such as injection schedule, fluid type, leak-off, and net pressure analysis). Eventually, the optimal injection scenario can be determined, which could be applicable for regions with similar geological conditions.
This study demonstrates how uncertainties can be narrowed down when estimating the stress condition from fracture injection tests. The proposed approach can identify critical parameters and suggest best practices for diagnostic fracture tests under certain reservoir conditions. It can also be coupled with an enhanced image log analysis to fully determine the in-situ stresses magnitude and direction, which will increase the reliability of related geomechanical and reservoir analyses.
The main objective of this paper is understanding the phenomenal anomalous diffusion flow mechanisms in unconventional fractured porous media. This understanding is crucial for estimating the impact of these flow mechanisms on pressure behavior, flow regimes, and transient and pseudo-steady state productivity index of the two cases of inner wellbore conditions: constant sandface flow rate and constant wellbore pressure. The targets are hydraulically fractured unconventional reservoirs characterized by porous media with complex structures. These media are consisted of a matrix and naturally induces fractures embedded in the matrix as well as hydraulic fractures.
Several analytical models for pressure drop and decline rate as wells productivity index in ultralow permeability reservoirs are presented in this study for the two inner wellbore conditions. A numerical solution is also presented in this study for pressure behavior using a linearized implicit finite difference method. The analytical models are developed from trilinear flow models presented in the literature with a consideration given to the temporal and spatial fractional pressure derivative for the ano malous diffusion flow that could be the dominant flow mechanism in the stimulated reservoir volume between hydraulic fractures. Mittag-Leffler functions are used for solving fractional derivatives of pressure and flow rate considering that temporal and spatial fractional exponents are less than one. Two solutions are developed in this study for the two inner wellbore conditions. The first represents the transient state condition that controls fluid flow in unconventional reservoirs for very long produc tion time. The second is the solution of pseudo-steady state condition that might be observed after transient state flow. The second solution is used for estimating stabilized pseudo-steady state productivity index considering different reservoir conditions. In the numerical solution, the temporal and spatial domains are discretized into several time steps and block-centered grids respectively. The results of the analytical models are compared with numerical solutions.
The outcomes of this study are: 1) Understanding the impact of temporal and spatial diffusion flow mechanisms on pressure behavior, flow rate declining pattern, and productivity index scheme during early and late production time. 2) Developing analytical and numerical models for fractional derivatives of pressure and flow rate considering diffusion flow mechanisms 3) Developing analytical models for different flow regimes that could be developed during the entire production life of reservoirs. 4) Studying the impact of reservoir configuration and wellbore type as well as different temporal and spatial diffusion flow conditions on stabilized pseudo-steady state productivity index. The study has pointed out: 1) Temporal and spatial diffusion flow have a significant impact on pressure drop, flow rate, and productivity index. 2) Wellbore pressure drop for constant Sandface flow rate declines rapidly as the temporal diffusion flow mechanism is the dominant flow pattern in the porous media. 3) Wellbore pressure drop for constant Sandface flow rate slightly increases during transient state flow as the spatial diffusion flow mechanisms increase and rapidly increases during pseudo-steady state flow. 4) Productivity index of diffusion flow is higher than the index of normal diffusion flow during transient and pseudo-steady state conditions. 5) The linear flow regime is most affected by anomalous diffusing flow and can be used to characterize the type of diffusion flow.
Ghadimipour, Amir (Baker Hughes, a GE Company) | Barton, Colleen (Baker Hughes, a GE Company) | Guises, Romain (Baker Hughes, a GE Company) | Perumalla, Satya (Baker Hughes, a GE Company) | Izadi, Ghazal (Baker Hughes, a GE Company) | Franquet, Javier (Baker Hughes, a GE Company) | Mahrooqi, Shabib (Petroleum Development Oman) | Dobroskok, Anastasia (Petroleum Development Oman) | Shaibani, Mahmood (Petroleum Development Oman)
As part of a multi-disciplinary investigation to optimize a tight reservoir development in the Sultanate of Oman, a comprehensive geomechanical characterization was performed and its results used as input for 3D non-planar hydraulic fracturing simulations. The simulation results led to better understanding of the reservoir response during hydraulic fracturing stimulation and thereby improved the decision making process for future field development. The focus of this paper is to highlight the geomechanical aspects of the analysis which explained several of the difficulties encountered during stimulation.
Geomechanical models were constructed covering the target sandstone and overlying clay-rich formation for ten horizontal and vertical wells by integrating diverse data including openhole logs, core rock mechanical tests, stress-induced failure interpretations from image logs, and stress measurements from mini-frac data. The geomechanical models were further supported by the results of available temperature, tracer and production logs. 3D geomechanical models were created by capturing the lateral and vertical variations of rock and geomechanical properties from these 1D models away from the wellbores, guided by the variations in seismic attributes using a co-simulation method. 3D modeling revealed a number of stress barriers supported by location of microseismic events in the target reservoir.
The geomechanical setting of the target formation is found to be complex with significant variations laterally and vertically. The West area of the field was found to have relatively lower stress compared to the Main area. Also, the Middle and Lower intervals of the target formation were shown to have considerably higher horizontal stresses (strike-slip/reverse faulting regime) compared to the Upper interval (normal/strike-slip faulting regime). The high stresses in Middle and Lower sections have the negative consequence of reducing the fraccability of these intervals as they require high breakdown pressures. In some cases, where breakdown was achieved, the resulting horizontal hydraulic fracture yields disappointing production results due to its inability to connect the reservoir vertically. Another important lesson learnt from geomechanical characterization in this field was the role of high angle bedding in truncating the vertical growth of hydraulic fractures. This understanding can further help to optimize the location of perforation intervals in stimulation designs of future development wells in this field.
Geomechanical characterization of this reservoir demonstrated considerable lateral and vertical heterogeneity that could only be captured by very detailed integration of well-based and seismic scale data. In addition, the effects of the
AL Isaee, Omar (Petroleum Development Oman) | Chavez Florez, Juan (Petroleum Development Oman) | Ali, Nada (Schlumberger) | AL Ghatrifi, Rawan (Petroleum Development Oman) | Al-Yaqoubi, Mazin (Petroleum Development Oman) | AL Abri, Ahmed (Petroleum Development Oman) | AL Hinai, Mohamed (Petroleum Development Oman)
In Oman, the unique geological properties of the reservoirs require different fracture strategies and technology deployment to make them commercially viable. Highly deviated wells, with multiple hydraulic fractures, have been identified as key technology enabler for the development of tight gas accumulations in Oman. The main objective of this study is to generate a 3D petrophysical and geomechanical view of the reservoir, to have a better understating of Hydraulic Fracturing for Horizontal and Highly Deviated Wells The comprehensive amount of data captured during the initial implementation phase of highly deviated wells covering reservoir characterization, fracture geomechanics as well as production logs in combination with the existent data captured in vertical wells, proves to be complex to analyze due to the volume of information and the multi variable nature associated with fracture and inflow predictions. A methodology was required where correlations and tendencies were identifiable at structural level, covering all target gas accumulations using all the static and dynamic captured data. The definition of a 3D Grid Visualization Block (3D-GVB) was introduced where all the captured parameters were distributed for analysis and interpretation. As a result of the appraisal and initial field development with vertical wells, it was possible to identify tight accumulations that will require dedicated highly deviated wells for its development. The initial phase of the implementation of highly deviated wells proves to be challenging, as the observed heterogeneities on geomechanical and petrophysical properties across the target gas accumulations, combined with differential depletion and the wells orientation to generate transverse fractures, creates a complex environment for fracture initiation and propagation, impacting not only fracture deployment but inflow deliverability of this wells. This paper will describe how the methodology uses a cycle of data analysis and interpretation to identify tendencies, that will lead to correlation and new algorithms that are retrofitted on the 3D-GVB platform, leading to optimization of well positioning at structural level, drilling and completion of this highly deviated wells. It will be described how this methodology is used for well positioning at structural level, to define well architectures oriented to enhance not only drilling, but also hydraulic fracturing and hydrocarbon deliverability on highly deviated wells. 2 SPE-197901-MS
Bai, Xiaohu (PetroChina Changqing Oilfield Company) | Zhang, Kuangsheng (PetroChina Changqing Oilfield Company) | Tang, Meirong (PetroChina Changqing Oilfield Company) | Wang, Chengwang (PetroChina Changqing Oilfield Company) | Wang, Guanggao (PetroChina Changqing Oilfield Company) | Li, Chuan (PetroChina Changqing Oilfield Company) | Zhang, Tongwu (PetroChina Changqing Oilfield Company) | Xu, Chuangchao (PetroChina Changqing Oilfield Company) | Wu, Shunli (PetroChina Changqing Oilfield Company) | Wang, Jianhui (PetroChina Changqing Oilfield Company) | Liu, Shun (PetroChina Changqing Oilfield Company) | Wang, Bei (PetroChina Changqing Oilfield Company) | Chen, Qiang (PetroChina Changqing Oilfield Company) | Fu, Yunlong (Fudan University)
The Chang7 group in Ordos Basin usually shows low brittleness index, high differential principle stress and little natural fracture, which makes it difficult to generate complex fractures with traditional high rate hydraulic fracture practice. During a geomechanical test on core samples, complex fractures were unexpectedly found inside the test sample due to fatigue failure after cyclical stress loading below fracture gradient. Based on cyclic stress loading tests on cores and large-scale mockups, a cyclic stress fracturing technology was developed with specific operation procedure, downhole tools and optimized fracturing design parameters to generate complex fractures. This technology injects high concentration slurry through tubing at low rate and slick-water through the annulus at various pump rate. The annulus injection rate changes constantly based on treating pressure and formation response, to achieve real-time control of bottomhole slurry concentration, in order to cyclically apply pressure on the formation rocks to induce fatigue failure, thus complex fractures are generated inside the low brittleness index Chang7 formation. In the field trial of 24 wells, the wells fractured with cyclic stress technology showed increased fracture complexity, a 100% increase in stimulated reservoir volume in microseismic monitoring result and achieved 50% higher production than the wells treated by conventional fracturing technology.