To stimulate a reservoir efficiently, multistage plug-and-perf completion and fracturing technologies are widely utilized to create multiple hydraulic fractures along a horizontal wellbore. However, excessive field cases and lab tests evidenced that, the simultaneous initiation and propagation of multiple fractures within a stage could compete with each other, cause uneven fluid and proppant partition into each placed cluster. Resulting in low cluster efficiency and non-uniform fracture development. Solid particulate diverters can aid to influence the fluid distribution between open clusters to optimize stimulation efficiency. The objective of this study is to use numerical models to thoroughly investigate the functionality of particulate system in fracturing process and optimize the completion and stimulation strategy under specific downhole conditions.
In this study, both CFD-DEM model and a 3D fracture simulator are employed to model fluid diversion and fracturing process for wells completed with plug-and-perf technique. For a field case study, sensitive analyses were performed to quantify the impact of completion design and pumping strategy on the resulted stimulation efficiency. The overall conductive reservoir volume is predicted to compare the cluster efficiency between different design scenarios. Thereafter, the stimulation efficiency of placed perforation clusters is analyzed and optimized with engineered solid particulate diverters.
For the presented particulate diversion technique, both in-stage and inter-stage fluid diversion are operationally feasible. From our analysis, engineered solid particulate diverters can effectively plug the active perforation clusters and build-up enough pressure to divert fracturing fluid into non-active perforation clusters to create additional fractures. Proper number of diverter pills and adequate pumping schedule can boost the cluster efficiency and eventually increase the conductive reservoir volume.
Through a field case study, the presented geomechanical analyses showed that the diverter design and operational parameters can be customized to enhance cluster efficiency. By adjusting completion design, the usage of particulate diverters can be optimized accordingly to maximize the stimulation efficiency. With the proposed efficient design, all the planned perforation clusters can develop and propagate hydraulic fractures and contribute to the overall production.
Performance comparisons of different tier friction reducers (FRs) using field water samples from the Delaware and Midland basins within the Permian Basin are discussed. The objective is to correlate them with their respective water mineralogy to identify the primary components affecting FR effectiveness, allowing a proper FR selection based on individual elements and not just by total dissolved solids (TDS). Identifying critical minerals that affect the proper FR selection enables making an educated FR selection not based on TDS count alone, which could potentially reduce the amount of testing and unsuccessful field trials. To zero in on the primary elements within the water that affect friction reduction behavior, extensive testing was performed. Traditional and inductive couple plasma (ICP) water analyses were performed to determine mineralogy, and flow loop testing was performed to determine FR performance. Additionally, specific parameters (i.e., hydration time, maximum FR percentage, and stability) were measured and compared to the multiple tests to determine trends between FR performance and water mineralogy. Understanding how a flow loop apparatus works is discussed, which helps when interpreting friction reduction performance. This is a fundamental component for understanding the behavior of the FR during testing and how it affects performance in the field. Additionally, this paper can be used as a basic guide for flow loop interpretation, and it attempts to identify possible causes of varying FR behavior in the field versus laboratory testing.
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.
Nunez, Alvaro Javier (Petroleum Development Oman) | Al-Farei, Ibrahim (Petroleum Development Oman) | Benchekor, Ahmed (Petroleum Development Oman) | Al Husaini, Nasser Khalfan (Petroleum Development Oman) | Sayapov, Ernest (Petroleum Development Oman) | Al-Shanfari, Abdul Aziz Salim (Petroleum Development Oman) | Al Bahri, Khalfan Mubarak Khalfan (Petroleum Development Oman) | Chavez, Juan Carlos (Petroleum Development Oman) | Al Hinai, Adnan Saif (Petroleum Development Oman)
Hydraulically fracturing operations is becoming much more complex as the gas formations are being depleted with the time. In addition to this, some gas reserves need to be recovered by fracturing horizontal wells with multiple stages which is the case of an extensive gas field in the Sultanate of Oman that has been producing since 1991 mainly by hydraulic fracturing. The scope of this paper is to discuss the different methodologies in the operations associated to hydraulic fracturing in horizontal gas wells with formations depleted in PDO, the main objective is to show operations and well delivery improvement by the optimization of tools conveyance, perforating techniques, clean out and milling strategy. The paper will show the enhancement of the operations and the outstanding results in these challenging well conditions. The paper will start by describing the different methods used to execute operations for fracturing horizontal wells which are mainly related to plug and perf technique, clean out and milling plugs in between stages. Further, it will discuss the strategy, planning and job execution of one of the wells with 14 stages in the horizontal section, the perforating technique and strategy used to help reduce screen out's, it will also discuss the acquisition of spectral Noise log data post fracturing with the assistance of Nitrogen as well as the milling of the isolation plugs at the end of the job. The optimization of the conventional operations is a novel approach to enhance hydraulic fracturing in depleted horizontal gas wells in PDO, this is in alignment with the continuous improvement ideas and the lean thinking across the oil and gas industry. It is easy to replicate in other horizontal wells to be hydraulically fractured which will reduce cost, HSE exposure and will help increase the recovery of hydrocarbon reserves.
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.