Production Of Tight Reservoirs Research Articles

Experimental Study of Forced Imbibition in Tight Reservoirs Based on Nuclear Magnetic Resonance under High-Pressure Conditions

This study utilizes nuclear magnetic resonance (NMR) techniques to monitor complex microstructures and fluid transport, systematically examining fluid distribution and migration during pressure imbibition. The results indicate that increased applied pressure primarily affects micropores and small pores during the initial imbibition stage, enhancing the overall imbibition rate and oil recovery. Higher capillary pressure in the pores strengthens the imbibition ability, with water initially displacing oil from smaller pores. Natural microfractures allow water to preferentially enter and displace oil, thereby reducing oil recovery from these pores. Additionally, clay minerals may induce fracture expansion, facilitating oil flow into the expanding space. This study provides new insights into fluid distribution and migration during pressure imbibition, offering implications for improved oil production in tight reservoirs.

Numerical Simulation Study of Pressure Transfer Based on the Integration of Fracturing, Shut-in and Production in Tight Reservoirs

As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of fracturing fluid. Therefore, it is especially critical to master the pressure transfer law during the shut-in process in tight reservoirs to further improve the energy efficiency of fracturing fluid. However, many studies have mostly focused on the separate design of fracturing, shut-in and production, and have not yet revealed the pressure transfer law during shutting in well based on the integration of fracturing, shut-in and production, which makes it difficult to realize the efficient development of tight oil and gas. Taking the tight oil reservoir in Block M as an example, the geological model of the target block was established using an integrated fracturing development software platform, on which the simulation of fracture extension, well shut-in and production was carried out. The changes in the reservoir pressure field during shutting in well were analyzed, and the influence law of fracturing fluid volume, shut-in time, reservoir original formation pressure and fracture network complexity on the effect of well shut-in were studied to optimize the shut-in system. It was found that the retained fluid increases, the pore pressure of the near-fracture matrix increases, and the diffusion distance of fracturing fluid to the distant matrix increases. The tight oil production increased after shutting in well, and the optimal retained fluid volume of 9600 m3 was actually preferred based on the model. The pore pressure of the near-fracture matrix decreases as the shut-in time increases, the diffusion distance of fracturing fluid to the distant matrix increases, and the pore pressure decreases with an increase in diffusion distance. The tight oil production increased after shutting in well, and the optimal shut-in time was actually preferred to be 90 days based on the model. The increase in formation pressure on abnormal low pressure formation is larger, and the production can be significantly improved after shutting in well. The more complex the fracture network is, the more obvious the non-uniform variation in matrix pore pressure during shutting in well. The research is of great significance for the optimal design of a shut-in system for tight reservoirs and the sustainable development of oil and gas resources in China.

Comparative Study between Different Oil Production Enhancement Scenarios in an Iraqi Tight Oil Reservoir

This paper presents a comparative study between different oil production enhancement scenarios in the Saadi tight oil reservoir located in the Halfaya Iraqi oil field. The reservoir exhibits poor petrophysical characteristics, including medium pore size, low permeability (reaching zero in some areas), and high porosity of up to 25%. Previous stimulation techniques such as acid fracturing and matrix acidizing have yielded low oil production in this reservoir. Therefore, the feasibility of hydraulic fracturing stimulation and/or horizontal well drilling scenarios was assessed to increase the production rate. While horizontal drilling and hydraulic fracturing can improve well performance, they come with high costs, often accounting for up to 100% of the total well cost. To ensure economically viable flow rates and achieve maximum ultimate oil recovery, a technical and economic comparative study was conducted. The results indicate that hydraulic fracturing offers promising outcomes, with a total oil production of 153,816 Mbbl over 30 years from 25 fractured wells, resulting in a final Net Present Value (NPV) of 3,583.32 MM$. In contrast, the planned two horizontal wells exhibit lower eventual production and NPV compared to the majority of fractured wells. However, the 2000 m lateral section of well HF00Y-S00YH shows a slightly higher NPV. Considering the operational benefits and profitability, hydraulic fracturing should be seriously considered for the further development of the Saadi reservoir. This comparative study provides valuable insights into the most effective approach for enhancing oil production in tight reservoirs like Saadi, balancing the technical feasibility and economic viability of different stimulation scenarios. The findings can guide decision-making processes and contribute to maximizing oil recovery in similar challenging reservoirs.

Coupling effect of critical properties shift and capillary pressure on confined fluids: A simulation study in tight reservoirs

Critical properties shift and large capillary pressure are important contributors for the phase behavior altering of nanopore fluid. However, the effects of critical properties shift and large capillary pressure on the phase behavior are ignored in traditional compositional simulators, leading to inaccurate evaluation results of tight reservoirs. In this study, phase behavior and production of confined fluid in nanopores are studied. First, we developed a method for coupling the effect of critical properties shift and capillary pressure into the vapor-liquid equilibrium calculation base on Peng-Robinson equation of state. Second, a novel fully compositional numerical simulation algorithm considering effect of critical properties shift and capillary pressure on phase behavior is accomplished. Third, we have discussed the alterations of critical properties shift effect, capillary pressure effect and coupling effect on the composition of oil and gas production in detail. The critical properties shift and capillary pressure effects on oil and gas production in tight reservoirs are analyzed quantitatively through four cases, and the influences of the two effects in oil/gas production are compared. Based on the fully compositional numerical simulation, the simulator can rigorously simulate the impacts of component changes during production. The simulation results show that both the critical properties shift effect and the capillary pressure effect reduce the bubble point pressure of Changqing shale oil, and the influence are more prevalent in pores of smaller radius. In pores is larger than 50 nm, the phase behavior altering of the fluid can be ignored. In addition, we devised four cases to comprehensively investigate the effects of critical properties shift and large capillary pressure on production performance of tight reservoirs. The comparisons between the four cases show that the capillary pressure effect impacts the reservoir production performances greater than the critical properties shift effect, such as higher oil production, higher GOR, and lower content of lighter component and higher content of heavier component in the residual oil/gas. The results of coupling effects indicate that the critical properties shift effect would suppress the effect of the capillary pressure effect. In particular, the difference between the simulation results of the coupling effects and the base case is smaller than that between the simulation results of the capillary pressure effect and the base case.

Experimental and Visual Analysis of Proppant-Slickwater Flow in a Large-Scaled Rough Fracture

SummaryUnderstanding proppant transport and distribution in hydraulic fractures is crucial to designing and optimizing hydraulic fracturing treatments in the field. The actual fracture surfaces are typically rough and form a tortuous pathway, significantly affecting proppant migration. However, many rough models are very small in size, and some have only one rough surface. Thus, it is inadequate to display proppant transport behaviors and placement laws.This study proposed a novel method to develop large-scale rough panels reproduced from actual hydraulic fractures. A large transparent slot (2×0.3 m) was successfully constructed to simulate a shear fracture with 5 mm relative displacement of two matched surfaces. Six kinds of proppants were selected to study the effects of particle density and size. Four types of slickwater were prepared to achieve viscous diversity. A high-resolution particle image velocimetry (PIV) system detected the instantaneous velocity and vector fields in the rough pathway to understand particle transport behaviors. The specific parametric study includes a quantitative analysis of the proppant bed profile, equilibrium height, coverage area, injection pressure, and volumes of proppant settled in the slot and outlet tank. Also, five tests are carried out in the smooth slot, which has the same size as the rough slot.The test results demonstrate that the narrow rough fracture would significantly hinder particle transport, especially in the horizontal direction. The proppant bed is higher and closer to the inlet than that in the smooth model. Particles mixed with highly viscous slickwater easily aggregate in the two-sided rough model and gradually form finger-like regions at the lower part of the inlet. The unstable flow and vortices can disperse aggregated particles and avoid particle clogging. Proppants injected at the high volume fraction are prone to settle quickly and build up a higher bed contact with the inlet, leading to more considerable injection pressure. Perforation blockage often occurred in the rough model, and the near-wellbore screenout was induced as the bed blocked all perforations. Enhancing the fluid carrying capacity and using smaller proppant help avoid perforation blockage and improve far-field fracture conductivity. Two correlations were developed to predict the equilibrium height and coverage area of the proppant bed. The experimental results and laws provide novel understandings that can help optimize hydraulic fracturing design and treatment by rationally selecting proppant and fracturing fluid to improve the productivity in tight reservoirs.

Optimization of Water Injection Strategy before Re-Stimulation Considering Fractures Propagation

Water injection before re-stimulation has a positive effect to mitigate the “frac hit” and increase oil production in tight reservoirs. However, the study of water injection strategy optimization has not been thoroughly investigated. Some conclusions can be found in the existing literature, but the pressure and stress distribution, fractures morphology and oil production were not considered as a whole workflow during the study. In addition, the different reservoir deficit was not considered. Although technical experience and economic benefit have been obtained in some field tests, failed cases still exist. To fill this gap, a series of numerical models are established based on a tight reservoir located in northwest China. Under the different re-stimulation timing, the pressure distribution, stress distribution, and fractures morphology after water injection of different injection/production ratios are calculated, respectively. The oil and water production are predicted. The results show that, after a short period of production with a small deficit, the degree of “frac hit” is slight. Injecting water has an obvious effect on increasing oil production for both parent and infill well. After a long period of production with a large deficit, the problem of “frac hit” is very severe. Injecting water has an obvious effect on increasing oil production only for the parent well. The production of infill well is influenced by the fractures’ interference and pressure increasing comprehensively. For the well group, measured by the final cumulative oil production, the optimal injection/production ratio is different, but the water injection volume is similar, which is about 15,000 m3.

Quantitative Evaluation of Well Performance Affected by Fracture Density and Fracture Connectivity in Fractured Tight Reservoirs

Understanding the relationship between petroleum recovery and characteristics of hydraulic fracture network is a key component of economic development of tight reservoirs. Owing to the limitations inherent in current reservoir simulators, optimization of fracture network has been simply focused on the parameters of fracture conductivity, fracture number, aperture, and so on. Deeper insight into the effect of decisive parameters, such as fracture density and fracture connectivity on the well production in tight reservoirs, is now required to maximize the petroleum recovery. In this work, a newly developed discrete fracture simulator is applied to comprehensively study the effect of fracture density and fracture connectivity in tight reservoirs. Conceptual models with different fracture densities and different fracture connectivity are firstly designed and simulated to explore how these two parameters affect the reservoir behavior and establish the equations for effect measurement. Then, we simulate models with different well placement strategies and a fixed set of natural fractures to determine the optimal strategy. Finally, simulations are performed on a field-scale reservoir with three long fractured horizontal wells. Results demonstrate that increases in either fracture density or fracture connectivity can significantly improve well production. However, an optimal value exists considering the economic profit. Compared to the fracture density, fracture connectivity plays a more important role in affecting the well production. In a tight reservoir with abundant natural fractures, making the horizontal well parallel to the direction of natural fractures is determined to be the optimal well placement strategy. The heterogeneous distribution of remaining oil in real tight oil reservoirs is mainly caused by the heterogeneous distribution of fracture density and fracture connectivity.

Synthetic model for evaluating CO2 flooding in tight oil reservoir

ABSTRACT With the increasing energy consumption and the exhaustion of conventional oil reservoir, CO2 flooding is becoming one of the key technologies to improve the oil production of tight reservoirs. Not only oil production of CO2 flooding but also its main influencing parameters and quantitative evaluation have attracted people’s attention in recent years. The experimental and numerical techniques are the main approach to evaluate the production and influencing parameters. However, it is expensive and costs a lot of time to use those approaches. To solve the above problems, in this paper, a comprehensive integrated hierarchy and correlation model is initially established to evaluate the production of CO2 flooding and confirm the main influencing parameters. Specifically speaking, the Analytic Hierarchy Process (AHP) and Grey Relationship Analysis (GRA) are used to evaluate the main influencing parameters of oil production for the CO2 flooding process in tight oil reservoirs, respectively. Subsequently, the Rank-Sum Ratio (RSR) is adopted to combine the Analytic Hierarchy Process with Grey Relationship Analysis to acquire the comprehensive weight and ensure the main influencing parameters. The results show that the comprehensive weight of permeability, variation coefficient, sand injection, and reservoir thickness is 0.1157, 0.0937, 0.0914, and 0.0895 and those parameters play a extremely important role in the production of CO2 flooding. The model is applied to eight production wells and the rank–sum ratio is 2.3 to 6.6. The arrange regular of comprehensive results evaluated by the rank–sum ratio has a very consistent relationship with that of production. It is convenient and accurate to evaluate the production-related parameters by using the comprehensive integrated-hierarchy model, and this study provides a functional method to analyze the production performance.

Multiphase Multicomponent Numerical Modeling for Hydraulic Fracturing with N-Heptane for Efficient Stimulation in a Tight Gas Reservoir of Germany

Conventionally, high-pressure water-based fluids have been injected for hydraulic stimulation of unconventional petroleum resources such as tight gas reservoirs. Apart from improving productivity, water-based frac-fluids have caused environmental and technical issues. As a result, much of the interest has shifted towards alternative frac-fluids. In this regard, n-heptane, as an alternative frac-fluid, is proposed. It necessitates the development of a multi-phase and multi-component (MM) numerical simulator for hydraulic fracturing. Therefore fracture, MM fluid flow, and proppant transport models are implemented in a thermo-hydro-mechanical (THM) coupled FLAC3D-TMVOCMP framework. After verification, the model is applied to a real field case study for optimization of wellbore x in a tight gas reservoir using n-heptane as the frac-fluid. Sensitivity analysis is carried out to investigate the effect of important parameters, such as fluid viscosity, injection rate, reservoir permeability etc., on fracture geometry with the proposed fluid. The quicker fracture closure and flowback of n-heptane compared to water-based fluid is advantageous for better proppant placement, especially in the upper half of the fracture and the early start of natural gas production in tight reservoirs. Finally, fracture designs with a minimum dimensionless conductivity of 30 are proposed.

Hydraulic Fracture Propagation and Analysis in Heterogeneous Middle Eastern Tight Gas Reservoirs: Influence of Natural Fractures and Well Placement.

Hydraulic fracturing is a stimulation process, most frequently used in tight and unconventional reservoirs for successful and economical hydrocarbon production. This study deals with the propagation behavior of induced hydraulic fractures (HFs) in naturally fractured formations within heterogeneous Middle Eastern tight gas reservoirs. Local sensitivity analysis was conducted for a Middle East candidate reservoir by varying fracture design parameters to investigate the fracture propagation behavior. After a comprehensive evaluation, a discrete fracture network-based simulator was used to introduce multiple sets of natural fractures (NFs) into the model to further analyze their interactions. Furthermore, simplistic wellbore placement analysis was also conducted. It is observed that production in tight reservoirs is governed by the presence of NFs and their distribution. This investigation analyzes HF propagation behavior and its correlated effects in the presence of NFs. Further assessment in terms of varying fracture geometry, NF sets, wellbore placement, and their effects on the conductivity are also presented. The introduced NF sets further illustrate the significance of the NF properties in this assessment. Additionally, variations in well placement demonstrate how effective the treatment can be in the presence of complex NF sets when properly located. The study is unique as it is one of its kind based on field data within the Middle East region and offers an insight into the potential concerns that may assist future fracturing operations within the region. The outcomes from this research validate the significance of NF orientation and its subsequent effects on the final HF geometry and network. Additionally, it further highlights the criticality of well placement and design strategies during hydraulic fracturing treatment design. Results describe how a minor modification with respect to the well placement can significantly affect hydraulic fracturing operations and subsequently the productivity and feasibility.

A compositional numerical study in hydraulic fractured tight reservoir: Considering capillary pressure in phase behavior calculation

The compositional numerical simulator is a critical method for simulating the development of oil and gas production. In the simulation of conventional reservoir, capillary pressure is relatively small and often been ignored in phase behavior calculations. But In tight reservoirs, the capillary pressure is so large that can seriously affect the fluid phase behavior. The existing compositional numerical simulators cannot accurately calculate oil and gas production of tight reservoirs because the effects of capillary pressure on phase behavior are ignored. In this paper, we developed a full compositional numerical simulator that simulates the production in tight reservoirs with the consideration of capillary effect on the phase behavior of fluid. To compare the simulation results with and without considering capillary pressure in phase behavior calculations, we respectively set the capillary pressure as a function of gas saturation or zero in matrix and fractures. Three capillary pressure assignment methods for tight reservoirs were performed to illustrate the influence of capillary pressure on production. The simulation results indicate that the consideration of capillary pressure on phase behavior lead to more favorable for oil production, such as lower cumulative gas production and gas-oil ratio, accelerated pressure drop rate, increased oil saturation, and higher recovery compositions of heavy components. This study provides reasonable simulation results for the actual production of tight reservoirs, giving important insights into the evaluation of the production and development from tight reservoirs.

Impacts of low harm fracturing fluid on fossil hydrogen energy production in tight reservoirs

The polymer fracturing fluid has been gradually used in the fossil hydrogen energy field. However, its impacts on the fields are still unclear. In this study, a series of experiments were conducted to solve the problem. First, a new method called the pressure transmission test (PTT) was used to evaluate the permeability damage induced by polymer fracturing fluid. Then several rock properties were tested to reveal rock potential damage induced by the aqueous fracturing fluid, after that the interactions between polymer fracturing fluid and rock were discussed in detail. Results showed that the average permeability pollution is 10.6. Permeability and X-ray diffraction (XRD) tests stated that the core is easier to be blocked by particles in the formation or fracturing fluid residue. Blocking and scanning electron microscope (SEM) tests showed that the nanoscale polymer would stick on the rock surface, and reduce the pore size. Our work provides a new method to evaluate the impact of polymer fracturing fluid on tight reservoirs. Moreover, the mechanism of permeability damage caused by the polymer fracturing fluid was also revealed.

Model of Effective Width and Fracture Conductivity for Hydraulic Fractures in Tight Reservoirs

Hydraulic fracturing technology is widely used in the development of tight reservoirs. Hydraulic fracture closure highly impacts oil and gas production in tight reservoirs, and a quantitative description of the effective width and fracture conductivity has a guiding significance for fracturing design and productivity prediction. In this paper, based on the mechanical characteristics of proppants in hydraulic fracturing, a fracture width model is first established for sandstone and shale reservoirs, and the effect of the closing pressure on the rock mechanics parameters of proppants is considered. Then, by the changes in fracture width and proppant permeability, a fracture conductivity model is built. Finally, the models are verified with existing experimental data, and are applied to analyze the influence of relevant parameters on the effective width and fracture conductivity of hydraulic fractures. Fracture closure is primarily affected by proppant deformation and embedment. An increase in the proppant elastic modulus can reduce proppant deformation and avoid fracture closure. A fracture containing large proppant more readily closes during the production process, and the closing pressure has a considerable effect on the proppant rock mechanical parameters, which can prevent the fracture from closing to maintain its conductivity. In this study, fracture closure and its conductivity are predicted, which is conducive to the production of tight reservoirs.

Integrated optimization design for horizontal well placement and fracturing in tight oil reservoirs

Hydraulically fractured horizontal well technologies, which combine hydraulically fractured technology with horizontal well technology, is widely used to enhance oil recovery in tight reservoir production. Although there are many advantages to this method, it requires more investment in drilling and completion. Most academic literature to date has treated the optimization of well placement and fracturing as two separate problems. Computationally expensive numerical simulation techniques are often involved both in well placement and fracturing design optimization processes, but only suboptimal solutions are achievable. In order to achieve co-optimization for horizontal well placement and fracturing, an optimal model has been constructed, with an objective function targeted at maximizing the net present value (NPV), which is a function of location, direction and length of a new horizontal well, the number of fractures, half-length of the fracture etc. Due to the large number of optimization variables, investigating the impacts of horizontal well parameters on the objective function must utilize repetitive runs of numerical simulations involving large computation times for evaluating possible well placement and fracturing scenarios. Aiming to address this challenge, a new method, called the Multipoint Adaptive Gaussian Process Surrogate Model with Important Design Domain (MAGPSM-IDD), is proposed. Then MAGPSM-IDD were applied to a synthetic field and a real reservoir, and our results showed that MAGPSM-IDD could obtain better results with higher efficiency than the popular optimization method, Hybrid Genetic Algorithm (HGA).

Technology Focus: Multilateral/Extended-Reach Wells (May 2016)

Technology Focus The development of multilateral wells and long-reach wells has become important to maximizing recovery for many fields. These technologies are often applied in offshore environments, where large reservoir areas are drained from one or more platforms. In the late 1980s, long-reach wells started to use existing infrastructure better by drilling beyond the design limits of that time. Several major operators were extending their limits, and, in the late 1990s, BP Wytch Farm showed that a horizontal departure exceeding 10 km was feasible. This had a significant effect on the industry because offshore platforms now could be designed for up to 10-km reach, as opposed to the early 1980s when 3-km reach was common. A field could now be developed with one platform instead of three, resulting in enormous savings. Multilateral-well technology also matured during the past 2 decades. There were many drivers for this development. One of the more important was the desire to increase production in tight reservoirs. Another advantage is directional control. Well stimulation with fracturing has the drawback that the fracture direction is controlled by the in-situ stresses in the rock. Multilateral branches, on the other hand, can be drilled in any direction. There has been considerable development around these technologies. Those that help clear the challenges, such as those related to wellbore stability, wellbore friction, equipment limitations, and operational aspects, can be considered mature technologies today. The main benefit from directional drilling is the maximizing of reservoir recovery. From this perspective, multilateral/ extended-reach wells may be considered one of the more important means of improved oil recovery. Although these directional-well concepts have been used for some years, they were initially costly with a high economic risk. There is a continuous technology development at many levels that leads to improvements. These result in more-efficient processes, with increased field recoveries as a consequence. Therefore, multilaterals and extended-reach wells are now common and will be very important for future cost-effective oil and gas production. Recommended additional reading at OnePetro: www.onepetro.org. SPE 174035 Technology Qualification and Installation Plan of Efficient and Accurate Multilaterals Drilling Stimulation Technology for Sandstone Oil Application by Kevin Rice, Fishbones, et al. SPE/IADC 168055 Expanding the Extended-Reach Envelope at Chayvo Field, Sakhlin Island by Vishwas P. Gupta, ExxonMobil, et al. SPE 168235 CT Extended Reach: Can We Reach Farther? by Ken Newman, KNewman Engineering, et al.

Optimization of Multi-Zone Unconventional (Shale) Gas Reservoir Using Hydraulic Fracturing Technique

Hydraulic fracturing is one of the most important stimulation techniques available to the petroleum engineer to extract hydrocarbons in tight gas sandstones. It allows more oil and gas production in tight reservoirs as compared to conventional means. The main aim of the study is to optimize the hydraulic fracturing as technique and for this purpose three multi-zones layer formation is considered and fractured contemporaneously. The three zones are named as Zone1 (upper zone), Zone2 (middle zone) and Zone3 (lower zone) respectively and they all occur in shale rock. Simulation was performed with Mfrac integrated software which gives a variety of 3D fracture options. This simulation process yielded an average fracture efficiency of 93.8%for the three respective zones and an increase of the average permeability of the rock system. An average fracture length of 909 ft with net height (propped height) of 210 ft (average) was achieved. Optimum fracturing results was also achieved with maximum fracture width of 0.379 inches at an injection rate of 13.01 bpm with 17995 Mscf of gas production.

Technology Focus: Multilateral/ Extended-Reach Wells (May 2015)

Technology Focus The development of multilateral wells and long-reach wells has become important to maximizing recovery for many oil fields. These technologies are often applied in offshore environments, where large reservoir areas are drained from one or more platforms. In the late 1980s, long-reach wells started to use existing infrastructure better by drilling beyond the design limits at that time. Several major operators were extending their limits, and, in the late 1990s, BP’s Wytch Farm showed that a horizontal departure exceeding 10 km was feasible. This had a significant effect on the industry because offshore platforms now could be designed for up to 10-km reach as opposed to the early 1980s, where 3-km reach was common. A field could now be developed with one platform instead of three, resulting in enormous savings. Multilateral-well technology also matured during the past 2 decades. There were many drivers for this development. One of the most important was the desire to increase production in tight reservoirs. Another advantage is directional control. Well stimulation with fracturing has the drawback that the fracture direction is controlled by the in-situ stresses in the rock. Multilateral branches, on the other hand, can be drilled in any direction. There is a considerable technology development around these technologies. Those that help clear the challenges such as those related to wellbore stability, wellbore friction, equipment limitations, and operational aspects can be considered mature technologies today. The main benefit from directional drilling is the maximizing of reservoir recovery. From this perspective, multilateral/extended-reach wells may be considered one of the most important means of improved oil recovery. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 163525 Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well by John Gradishar, Shell, et al. SPE/IADC 163487 Case History of a Challenging Thin-Oil-Column Extended- Reach-Drilling Development at Sakhalin by Vishwas P. Gupta, ExxonMobil, et al. SPE 170831 Going Long—Overcoming Challenges in Completing 3600-m Laterals by R. Liston, Step Energy Services, et al.

Technology Focus: Tight Reservoirs (October 2013)

Technology Focus Tight reservoirs are still in the early stages of becoming a dominant source of energy and economic growth throughout the world for years to come. I recently read two distinctly different articles particularly relevant to tight reservoirs. One was written by an oil and gas consultant who applied the Pareto principle to the practice of multistage hydraulic fracturing of horizontal wells, which has pushed oil production to 20-year highs in North America. The other was authored by a major asset holder’s policy expert, who objectively addressed public perception of the oil and gas industry. Although our industry has developed a number of new technologies enabling better reservoir characterization, horizontal-well placement, and reservoir drainage, as well as gaining public trust, there does appear to be room for improvement. We must continue to listen to the public and understand the concerns and issues. Our response should include transparency, research to address concerns, and development of workflows and technologies to address safety and protection of health and the environment. One such response by our industry is the growing priority of improving long-term wellbore integrity. Improvements are being made in mud removal, cement-system-design software and techniques, and environmentally friendly cementing systems with improved bonding and mechanical integrity. From a production perspective, if 80% of production is coming from 20% of the stages, our industry needs to Ensure that wellbores and fracture stages result in quality production Recover the bypassed oil and gas Evolve laboratories to understand the complex chemistry and physics of tight reservoirs Experience demonstrates that generalized field development and production planning do not offer optimal resource recovery in tight reservoirs. Case studies show us that customized planning for landing the well, stimulating the reservoir, and producing the asset is the way to go. As this decade unwinds, we will see new workflows and technologies to ensure that wellbores are landed better, fracture stages are placed better, and bypassed oil and gas are recovered. The laboratories of the future and new technologies created for refracturing/re-entry programs are of particular interest to me. Laboratory studies to determine fluid efficiency in a fracture need to reflect tight-reservoir conditions and not that of American Petroleum Institute RP 13M-4. Rock/fluid interactions are much more influential in tight reservoirs, and the industry needs to improve its methodology and standardization in such test measurements. Refracturing programs will be challenged to promote stimulation of new zones outside of those stimulated by the initial fracturing and restimulation of closed or damaged networks. New diversion technologies to simplify operations and reduce costs are to be anticipated for tight-reservoir production. Recommended additional reading at OnePetro: www.onepetro.org. SPE 159546 Stimulated-Shale-Volume Characterization: Multiwell Case Study From the Horn River Shale: II. Flow Perspective by Christine A. Ehlig-Economides, Texas A&M University, et al.

Lowering the phase-trap damage in tight-gas reservoirs by using interfacial tension (IFT) reducers

Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc). One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly. This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.

Fracturing in Tight Gas Reservoirs: Application of Special-Core-Analysis Methods To Investigate Formation-Damage Mechanisms

Summary Gas-well productivity in tight reservoirs is greatly impeded by fracturing-fluid interactions with the formation. New simulators introduce formation-damage mechanisms to calculate gas-well productivity. However, equations describing formation damage must be supported by experimental data obtained in conditions representative of fracturing operations. The purpose of this work is to derive absolute-permeability and multiphase-flow damages upon return gas permeability after core invasion by a fracturing fluid by methods used in the Special Core Analysis Laboratory (SCAL). The core permeability is in the microdarcy range with significant illitic content. Absolute-permeability damages caused by fracturing-fluid filtration and water sensitivity are measured. Water-saturation profiles recorded by X-ray in two-phase-flow experiments are interpreted. The methodology of interpretation provides the petrophysical data specific to the rock/fluid system: absolute permeability, relative permeability damage caused by hysteresis, and capillary pressure. In addition, simulations are presented for the evaluation of the effect of various operational parameters, such as pressure drawdown, on gas productivity. It is shown that permeability hysteresis is the determinant factor to explain low gas recoveries at short term. In the long term, the natural cleanup is very slow. The results, derived from a real rock/fluid system, are used to provide recommendations for improving backflow procedures. This methodology can be applied to any case of damage caused by the alteration of rock/fluid properties.