The fundamental behavior of fluid production from shale/ultra-low permeability reservoirs that are produced under a constant wellbore pressure remains difficult to quantify, which is believed to be (at least in part) due to the complexity of the hydraulic fracture patterns created during the well stimulation process. This work introduces a novel approach to model the hydraulic fractures in a shale reservoir using a stochastic method called random-walk. We see this approach as a beginning step that could be used to capture a part of the "complexity" of a fracture that has been generated by a hydraulic fracturing treatment and that such "complex" fracture processes may be observed in the Microseismic measurements.To assess the random-walk fracture concept, we performed numerical simulation of the patterns generated using a given random-walk fracture pattern. Using a total of 83 pattern cases, sensitivity analyses were performed on these fracture patterns; where the tortuosity, the extent (length), the tendency to split, and the number of branching stages were the factors considered. The rate performance of the "random-walk" fracture cases were compared to the standard model of a (single) planar hydraulic fracture. In addition to the mass rate performance, the created pressure distribution was analyzed in "time slices" (or "snapshots) to qualitatively assess each complex-pattern during early production times (before the onset of the pseudosteady-state flow regime).Our results were used to create a correlation between fracture performance, in terms of cumulative recovery, and the fracture volume and "complexity." In addition, an empirical correlation between the number of stages of bifurcation (splitting) of the fracture pattern and the value of the mass rate derivative for early production times was then established. Finally, as we were limited to a small-scale case due to the intensive gridding required, the feasibility and the advantages of a full-scale reservoir and well model are discussed.iii DEDICATION I dedicate this work to:The love of my life Hana; for all the encouragement that inspired me to complete this work.My parents, Nabil and Fatma; who never stopped believing in me. My sisters; Wafa and Hela. iv ACKNOWLEDGEMENTS I would like to express my gratitude to the following people that contributed to this work: Dr. Thomas A. Blasingame for his supervision, his patience and his demand for perfection; Dr. Walter B. Ayers for the quality of his lessons and his contribution in this work; Dr. Maria A. Barrufet for her kindness and precious advice; Dr. George J. Moridis for providing the base numerical simulator, and his demand for perfection; Dr. Peter P. Valkó for his assistance and guidance and Dr. Spiros Vellas (Texas A&M supercomputing facility) who provided supercomputer access. CHAPTER I Figure 40 -5 tri-branched fracture patterns (cases 1 to 5).The investigation of the production curves of Figure 41 and Figure 42 shows that between and the flow exhibits a linear behavior with a similar slope for differen...

It is becoming more common for operators around the world to use alleged conformance control completions as a means of managing inflow zones and controlling production. When this type of completion is introduced in a field, it is extremely important to analyze its effectiveness at very early stages of the project to achieve maximized zonal contribution together with proper compartmentalization in current and subsequent completions, since this will have a significant impact on the future life of the entire field. A thorough analysis should include understanding zonal isolation before and after acid stimulation, fluid distribution inside the compartments during the treatment, and confirmation of completion integrity. Analyzing completion performance by introducing additional downhole monitoring systems or devices is costly and is more appropriate for the long term. Another option, surveillance with wireline technology, may not provide definite conclusions due to limited acquisition extent. Alternatively, coiled tubing (CT) can provide a fit-for-purpose integrated solution to data acquisition and analysis challenge. The proposed approach uses distributed temperature sensing technology along with real-time data streaming capabilities to provide an instantaneous insight on wellbore dynamics, thus enabling informed decisions on treatment optimization, as well as yielding reliable information on interzonal communication. This study is based on a success story of intervening with CT on 10 wells, with a total of 40 compartments in a carbonate reservoir in the Caspian region. Distributed temperature evolution models are used to build a signature library characteristic of specific flow events in the wellbore. The study consists of distributed temperature surveys lasting from 30 minutes to 6 hours that were acquired before and during the acid stimulation of each conformance compartment. Unique temperature features are identified in specific flow events, such as communication between compartments, loss of completion integrity, and effective stimulated area determination, to name a few. Those events are hypothesized and corroborated using downhole point measurements. A significant finding is that communication between zones occurs through several possible paths (i.e., through the formation/matrix or via the completion). The stimulation strategy can be modified accordingly, leveraging downhole data to maximize completion efficiency. This combination of transient distributed temperature and point measurement data provides an insight into wellbore and reservoir flow dynamics and facilitates an optimized stimulation strategy.

Efficient reservoir sweep is critical for operators to boost oil production in the Middle East. This task becomes particularly challenging in carbonate formations, which typically feature permeability ranging from microscopic pores to large cavernous vugs. Extreme heterogeneity disserves water injectors, leading to nonuniform injection profiles. Consequently, water sweeping is inefficient and leaves significant residual oil behind. In the Mesopotamian Basin, the matrix stimulation approach was rethought to address high permeability contrasts and produce the bypassed oil. The methodology relied on coiled tubing (CT) equipped with fiber optics and real-time downhole measurements, a CT-deployed inflatable packer, and a high-pressure rotary jetting tool. The array of downhole readings was leveraged to ensure optimal use of the bottomhole assembly. The high-pressure rotary jetting tool was used in the first run to condition the wellbore tubulars across the inflatable packer planned anchoring depth. In the second run, the inflatable packer was set at the target depth, and the stimulation treatment was selectively pumped either above or below the packer, depending on the depth of the interval of interest. The proposed stimulation technique was implemented in more than 40 wells, which included vertical and deviated water injectors, completed with 3 1/2-in. or 4 1/2-in. tubing and up to 7-in. casing, with two to five perforated intervals averaging 30 to 50 m in total, temperatures ranging from 90 to 140°F, and an average meadured depth of 2500 m. The CT-deployed inflatable packer had an expansion ratio of up to 3 to 1. CT real-time downhole measurements, such as CT internal pressure, CT annulus pressure, temperature, downhole axial forces, gamma ray, and casing collar locator (CCL), were instrumental to eliminate the uncertainties associated with changing downhole conditions and depth correlation. They also enabled a controlled actuation of the downhole tools in subhydrostatic wells, as the pressure imbalance caused by the low bottomhole pressure can generate loss of fluid flow and pressure across the tools. For the first time, the operator was able to stimulate the tight rock in water injector wells, enhancing injection sweeping efficiency and boosting oil production from offset wells. As a result of this campaign, production gains are estimated at 60,000 BOPD, and injectivity increased in average 2 times per intervention. This approach has now become the state of the practice for the operator to stimulate wells with high permeability contrast. This enhanced matrix stimulation technique, leveraged by CT and real-time downhole measurements, brings a new level of confidence to accurately and effectively deploy inflatable packers in wells with challenging expansion ratio and low reservoir pressure. In addition, the proposed technique enables stimulating tight rock across intervals with extreme heterogeneity, resulting in a more efficient sweep and an increase in oil production.

In onshore Middle East, local practices for matrix stimulation of openhole horizontal carbonate water injectors consist of spotting hydrochloric acid treatment via coiled tubing (CT) along the uncased section using a specific fluid dosage per unit length of the pay zone. Thus far, that approach has delivered inconsistent results in wells completed across tight carbonate rock, most often leading to a rapid decline in injection rates following the treatment. An alternative workflow was implemented to take full advantage of real-time downhole measurements and the presence of fiber optics in the CT for telemetry. The approach leverages distributed temperature sensing (DTS) to evaluate the original water injection coverage across the reservoir. Results enable segmenting the open hole into intervals requiring different levels of stimulation. Each section benefits from a customized treatment that increases injectivity and improves uniformity of injection. A high-pressure jetting tool, controlled with the help of real-time downhole pressure data, is key to that workflow because it enhances penetration of acid into the targeted intervals. Previous studies showed that energized acid is key to a successful stimulation of tight carbonates. However, the use of CT to convey and pump acid along the open hole often limits the rate at which fluid is pumped, and customized nozzles may fall short of expectations if the downhole conditions are not favorable to their proper actuation. The introduction of real-time downhole readings and DTS surveying into the stimulation workflow helped overcome those limitations and get the most out of equipment and fluids. DTS offers a visualization of high- and low-intake zones along the open hole throughout the operation, thus enabling informed decisions on design adjustments for each stimulation stage. Downhole pressure measurement is instrumental in determining whether downhole conditions are favorable for the use of the high-pressure jetting nozzle, which has a direct impact on the exact pumping sequence, with the potential addition of stimulation stages to bring the openhole in optimum conditions. Downhole pressure reading also allows optimal operation of the jetting nozzles within the designed range. The engineered workflow has been successfully implemented delivering injectivity improvements of nearly 8,000 B/D in the intervened wells, with the DTS survey confirming significant gains on injection coverage along the openhole section. This advanced matrix stimulation workflow, brings reliability and flexibility to the acidizing of tight carbonate water injectors. Use of the full array of downhole parameters not only yields unprecedented injection coverage in complex reservoirs, it also eliminates uncertainties associated with wellbore conditions and helps in keeping injection under the fracturing gradient, thus eliminating the risk of differential sticking events.

Conventional production logging with electric line is sometimes challenged by the presence of mechanical restrictions in the wellbore. The fragility of production logging tools also impedes the use of electric-line coiled tubing (CT) with the risk of damaging tools across sections with little clearance. This study showcases conclusive flow profiling using distributed temperature sensing (DTS) via fiber optics deployed with CT in a gas condensate well where wellbore access prevented the use of logging tools. Flow profiling via DTS has been used globally in completions where fiber optic lines are permanently installed. Interpretation of those logs usually leverages months of acquired data to invert temperature information and obtain the evolution of flow distribution over time. The proposed methodology instead relies on hours of DTS acquisition through the temporary deployment of fiber optics with CT. A comprehensive sensitivity analysis on key unknown parameters is then performed using a fit-for-purpose thermal-flow simulator to match simulated and acquired temperature profiles, leading to a flow distribution of gas, condensate, and oil in the wellbore. Before the intervention, an evaluation study was run using a flow-thermal simulator to evaluate the expected sensitivity of wellbore temperature to poorly characterized downhole parameters, such as permeability, pressure, or skin. This allows determining the downhole conditions under which DTS is able to detect flow contribution for a specific candidate. During the operation, the CT equipped with fiber optics was stationed across production zones for a total of 06 hours. The data was processed and fed back to the simulator along with reservoir, well data, and surface rates. To further constrain data processing, pressure surveys were acquired during the CT run using a downhole gauge, both during flow and shut-in periods. Unknown reservoir properties were sensitized during data interpretation to obtain a match between acquired DTS profiles and simulated wellbore temperature evolution, which, in turn, yielded an associated flow distribution. The matching exercise being an open-ended mathematical problem, several scenarios were considered, and their results checked against further production characterization of the wellbore and the field. The proposed case study illustrates how this methodology enabled logging in a mechanically-restricted zone and helped determining that the top interval was not contributing to flow. Flow profiling can be performed using a wide range of complementary logging tools, but the evolution of completions over the past few years is increasingly introducing mechanical restrictions that prevent the conveyance of such tools altogether. This study demonstrates that DTS can be a viable alternative for assessing zonal flow contributions. It also discusses the conditions under which this methodology is achievable.