An Innovative Approach to Install Production String with ESP to Avoid Productivity Impairment in Multistage Fractured Horizontal Well

2021 ◽  
Author(s):  
Muhammad Nadeem Aftab ◽  
Kashif Amjad ◽  
Ayman Elmansour ◽  
Animekh Talukdar ◽  
Ahmed Rashed AlHanaee ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Fractured Reservoirs ◽  
Internal Diameter ◽  
Production Test ◽  
Fractured Reservoir ◽  
Process Selection ◽  
Hydrocarbon Production ◽  
Advantages And Disadvantages ◽  
Artificial Lift ◽  
Tight Carbonate

Abstract Objectives/Scope Generally, tight reservoirs require hydraulic fracturing to enhance and sustain hydrocarbon production. However, fracturing requires frac string with bigger Internal Diameter (ID) to minimize frictional losses during hydraulic fracturing operation. This string ID may not be suitable to provide optimum Vertical Lift Performance (VLP) during production phase, particularly in oil wells. Therefore, it is required to replace the frac string with production string of smaller ID. Occasionally, artificial lift also becomes essential to overcome VLP issues in future due to progressive water production and declining reservoir pressure. Methods, Procedures, Process Completion replacement often causes reservoir damage due to killing operation, which can be removed in conventional carbonate reservoirs by matrix stimulation. However, formation damage removal is difficult in hydraulically fractured tight carbonate and sandstone reservoirs. Preventive measures become essential to avoid productivity impairment particularly in hydraulically fractured reservoirs. Different preventative options are proposed and reviewed to isolate reservoir with their advantages and disadvantages. After comprehensive studies and risk assessments, an innovative modification in the completion plan was introduced and finalized. This plan includes production string with Electrical Submersible Pump (ESP) to improve VLP. This completion provides full accessibility intervention job, which may be required for reservoir monitoring and surveillance in future. Results, Observations, Conclusions A comprehensive production test is performed to evaluate and compare the testing results of pre and post workover. Testing results show there is no impairment in productivity of the reservoir, which is avoided in workover process by isolating reservoir section. This paper summarizes the completion design process, selection criteria, challenges, and lessons learnt during design and execution phases. This technique will provide the guidelines for installation of the Production string/ESP in hydraulically fractured reservoir without productivity impairment. Novel/Additive Information With modified design, the reservoir is isolated from wellbore and completion with ESP is run successfully without killing reservoir section. Underbalance conditions are achieved prior to establishing communication between reservoir and wellbore.

Evaluating the Performance of Surfactants in Enhancing Flowback and Permeability after Hydraulic Fracturing through a Microfluidic Model

SPE Journal ◽  
1900 ◽  
Vol 25 (01) ◽  
pp. 268-287 ◽  
Author(s):  
Tianbo Liang ◽  
Ke Xu ◽  
Jun Lu ◽  
Quoc Nguyen ◽  
David DiCarlo
Keyword(s):  
Hydraulic Fracturing ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
Phase Changes ◽  
Screening Criteria ◽  
Hydrocarbon Production ◽  
Glass Micromodel ◽  
The Matrix ◽  
Production Stages ◽  
The Impact

Summary Hydraulic fracturing can create a large fracture network that makes hydrocarbon production from low-permeability reservoirs economical. However, water can invade the rock matrix adjacent to the created fractures and generate water blockage that impairs production. Using surfactants as fracturing-fluid additives is a promising method to enhance the fluid flowback, and thus mitigate the water blockage caused by invasion. It is imperative to understand how surfactants work during the fracturing and production stages, so as to maximize their effectiveness in production enhancement. In this study, an experimental investigation is conducted using a “chipflood” sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically fractured reservoirs. All experiments are conducted in a 2.5D glass micromodel that provides direct observation of in-situ phase changes when different Winsor types of microemulsions formed in the porous medium. The results provide direct evidence of the impact of the matrix–fracture interaction as well as water removal when surfactants are used. They further elucidate why surfactants under different Winsor-type conditions perform differently in mitigating the water blockage. This helps to clarify the screening criteria for optimizing flowback surfactant in hydraulic fracturing.

Forecasting the Water Flooding for the Production Wells of a Gas Condensate Field with a Fractured Reservoir Type

2021 ◽  
Author(s):  
Pavel Dmitrievich Gladkov ◽  
Anastasiia Vladimirovna Zheltikova
Keyword(s):  
Produced Water ◽  
Fractured Reservoirs ◽  
Gas Condensate ◽  
Water Flooding ◽  
Fractured Reservoir ◽  
Well Performance ◽  
Integrated Monitoring ◽  
Field Development ◽  
Water Gas ◽  
Gas Ratio

Abstract As is known, fractured reservoirs compared to conventional reservoirs have such features as complex pore volume structure, high heterogeneity of the porosity and permeability properties etc. Apart from this, the productivity of a specific well is defined above all by the number of natural fractures penetrated by the wellbore and their properties. Development of fractured reservoirs is associated with a number of issues, one of which is related to uneven and accelerated water flooding due to water breakthrough through fractures to the wellbores, for this reason it becomes difficult to forecast the well performance. Under conditions of lack of information on the reservoir structure and aquifer activity, the 3D digital models of the field generated using the hydrodynamic simulators may feature insufficient predictive capability. However, forecasting of breakthroughs is important in terms of generating reliable HC and water production profiles and decision-making on reservoir management and field facilities for produced water treatment. Identification of possible sources of water flooding and planning of individual parameters of production well operation for the purpose of extending the water-free operation period play significant role in the development of these reservoirs. The purpose of this study is to describe the results of the hydrochemical monitoring to forecast the water flooding of the wells that penetrated a fractured reservoir on the example of a gas condensate field in Bolivia. The study contains data on the field development status and associated difficulties and uncertainties. The initial data were results of monthly analyses of the produced water and the water-gas ratio dynamics that were analyzed and compared to the data on the analogue fields. The data analysis demonstrated that first signs of water flooding for the wells of the field under study may be diagnosed through the monitoring of the produced water mineralization - the water-gas ratio (WGR) increase is preceded by the mineralization increase that may be observed approximately a month earlier. However, the data on the analogue fields shows that this period may be longer – from few months to two years. Thus, the hydrochemical method within integrated monitoring of development of a field with a fractured reservoir could be one of the efficient methods to timely adjust the well operation parameters and may extend the water-free period of its operation.

Numerical Simulation of Proppant Transport in Hydraulically Fractured Reservoirs

2021 ◽  
Author(s):  
Seyhan Emre Gorucu ◽  
Vijay Shrivastava ◽  
Long X. Nghiem
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fractured Reservoirs ◽  
Injection Timing ◽  
Fracture Permeability ◽  
Step Size ◽  
Time Step ◽  
Time Step Size ◽  
Proppant Transport ◽  
Fracture Closure

Abstract An existing equation-of-state compositional simulator is extended to include proppant transport. The simulator determines the final location of the proppant after fracture closure, which allows the computation of the permeability along the hydraulic fracture. The simulation then continues until the end of the production. During hydraulic fracturing, proppant is injected in the reservoir along with water and additives like polymers. Hydraulic fracture gets created due to change in stress caused by the high injection pressure. Once the fracture opens, the bulk slurry moves along the hydraulic fracture. Proppant moves at a different speed than the bulk slurry and sinks down by gravity. While the proppant flows along the fracture, some of the slurry leaks off into the matrix. As the fracture closes after injection stops, the proppant becomes immobile. The immobilized proppant prevents the fracture from closing and thus keeps the permeability of the fracture high. All the above phenomena are modelled effectively in this new implementation. Coupled geomechanics simulation is used to model opening and closure of the fracture following geomechanics criteria. Proppant retardation, gravitational settling and fluid leak-off are modeled with the appropriate equations. The propped fracture permeability is a function of the concentration of immobilized proppant. The developed proppant simulation feature is computationally stable and efficient. The time step size during the settling adapts to the settling velocity of the proppants. It is found that the final location of the proppants is highly dependent on its volumetric concentration and slurry viscosity due to retardation and settling effects. As the location and the concentration of the proppants determine the final fracture permeability, the additional feature is expected to correctly identify the stimulated region. In this paper, the theory and the model formulation are presented along with a few key examples. The simulation can be used to design and optimize the amount of proppant and additives, injection timing, pressure, and well parameters required for successful hydraulic fracturing.

Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs

2015 ◽  
Vol 18 (02) ◽  
pp. 187-204 ◽  
Author(s):  
Fikri Kuchuk ◽  
Denis Biryukov
Keyword(s):  
History Matching ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Naturally Fractured Reservoirs ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Fractured Reservoir ◽  
Pressure Transient ◽  
Matrix Block ◽  
Naturally Fractured

Summary Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs include fractured igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected-network dual-porosity systems). In this paper, we investigate the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. Unlike the single-derivative shape of the Warren and Root (1963) model, fractured reservoirs exhibit diverse pressure behaviors as well as more than 10 flow regimes. There are seven important factors that dominate the pressure-transient test as well as flow-regime behaviors of fractured reservoirs: (1) fractures intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; (2) fractures intersect the wellbore with dipping angles from 0° to less than 90°; (3) fractures are in the vicinity of the wellbore; (4) fractures have extremely high or low fracture and fault conductivities; (5) fractures have various sizes and distributions; (6) fractures have high and low matrix block permeabilities; and (7) fractures are damaged (skin zone) as a result of drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes were compared with those from the field data. We performed history matching of the pressure-transient data generated from our discretely and continuously fractured reservoir models with the Warren and Root (1963) dual-porosity-type models, and it is shown that they yield incorrect reservoir parameters.

The Role of Microbiology in Models of Dental Caries: Reaction Paper

1995 ◽  
Vol 9 (3) ◽  
pp. 255-269 ◽  
Author(s):  
G.H. Bowden
Keyword(s):  
Process Selection ◽  
Advantages And Disadvantages ◽  
Test Models ◽  
Plaque Development ◽  
In Vitro Systems ◽  
Selection Of

Models of the caries process have made significant contributions toward defining the roles of bacteria in caries. Microbiologists use a variety of in vitro systems to model aspects of the caries process. Also, in situ models in humans provide information on the microbiology of caries in vivo. These models do not involve the entire process leading to natural caries; consequently, the results from such studies are used to deduce the roles of bacteria in natural caries. Therefore, they can be described as Inferential Caries Models. In contrast, animal models and some clinical trials in humans involve natural caries and can be described as Complete Caries Models. Furthermore, these models are used in two distinct ways. They can be used as Exploratory Models to explore different aspects of the caries process, or as Test Models to determine the effects of anticaries agents. This dichotomy in approach to the use of caries models results in modification of the models to suit a particular role. For example, if we consider Exploratory Models, the in situ appliance in humans is superior to others for analyzing the microbiology of plaque development and demineralization in vivo. The chemostat and biofilm models are excellent for exploring factors influencing bacterial interactions. Both models can also be used as Test Models. The in situ model has been used to test the effects of fluoride on the microflora and demineralization, while the chemostat and biofilm models allow for the testing of antibacterial agents. Each model has its advantages and disadvantages and role in analysis of the caries process. Selection of the model depends on the scientific question posed and the limitations imposed by the conditions available for the study.

High Pressure, High Temperature Bioreactors as a Biocide Selection Tool for Hydraulically Fractured Reservoirs

2021 ◽  
Author(s):  
Joseph Ferrar ◽  
Philip Maun ◽  
Kenneth Wunch ◽  
Joseph Moore ◽  
Jana Rajan ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Hydraulic Fracturing ◽  
Fractured Reservoirs ◽  
Field Trials ◽  
Detectable Level ◽  
Program Optimization ◽  
Microbial Counts ◽  
Selection Tool ◽  
High Pressure High Temperature

Abstract We report the design, operation and biogenic souring data from a first-of-its kind suite of High Pressure, High Temperature (HPHT) Bioreactors for hydraulically fractured shale reservoirs. These bioreactors vet the ability of microbial control technologies, such as biocides, to prevent the onset of microbial contamination and reservoir souring at larger experimental volumes and higher pressures and temperatures than have been previously possible outside of field trials. The bioreactors were charged with proppant, crushed Permian shale, and sterile simulated fracturing fluids (SSFF). Subsets of bioreactors were charged with SSFF dosed with either no biocide, tributyl tetradecyl phosphonium chloride (TTPC, a cationic surface-active biocide), or 4,4-dimethyloxazolidine (DMO, a preservative biocide). The bioreactors were shut in under 1,000-2,500 psi and elevated temperatures for up to fifteen weeks; hydrogen sulfide (H2S) and microbial counts were measured approximately once per week, and additional microbes were introduced after weeks three and five. Across two separate studies, the bioreactors containing no biocide soured within the first week of shut-in and H2S concentrations increased rapidly beyond the maximum detectable level (343 ppm) within the first three to six weeks of shut-in. In the first study, the bioreactors treated with TTPC soured within two weeks of shut-in (prior to the first addition of fresh microbes), and H2S concentrations increased rapidly to nearly 200 ppm H2S within the first six weeks of shut-in and beyond the maximum detectable level after fifteen weeks of shut-in. The bioreactors containing DMO did not sour during either study until at least the first addition of fresh microbes, and higher levels of the preservative biocide continued to prevent the biogenic formation of H2S even during and after the addition of fresh microbes. Microbial counts correlate with the H2S readings across all bioreactor treatments. The differentiation in antimicrobial activity afforded by the different types of biocide treatments validates the use of these simulated laboratory reservoirs as a biocide selection tool. This first-of-its-kind suite of HPHT Bioreactors for hydraulic fracturing provides the most advanced biocide selection tool developed for the hydraulic fracturing industry to date. The bioreactors will guide completions and stimulation engineers in biocide program optimization under reservoir-relevant conditions prior to beginning lengthy and expensive field trials.

Predicting Hydraulic Fracturing in a Carbonate Gas Reservoir in Abu Dhabi Using 1D Mechanical Earth Model: Uncertainty and Constraints

2015 ◽  
Author(s):  
Manhal Sirat ◽  
Mujahed Ahmed ◽  
Xing Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Abu Dhabi ◽  
Hydraulic Fractures ◽  
Gas Reservoir ◽  
In Situ Stresses ◽  
Tight Carbonate ◽  
Different Depths

Abstract In-situ stress state plays an important role in controlling fracture growth and containment in hydraulic fracturing managements. It is evident that the mechanical properties, existing stress regime and the natural fracture network of its reservoir rocks and the surrounding formations mainly control the geometry, size and containments of produced hydraulic fractures. Furthermore, the three principal in situ stresses' axes swap directions and magnitudes at different depths giving rise to identifying different mechanical bedrocks with corresponding stress regimes at different depths. Hence predicting the hydro-fractures can be theoretically achieved once all the above data are available. This is particularly difficult in unconventional and tight carbonate reservoirs, where heterogeneity and highly stress variation, in terms of magnitude and orientation, are expected. To optimize the field development plan (FDP) of a tight carbonate gas reservoir in Abu Dhabi, 1D Mechanical Earth Models (MEMs), involving generating the three principal in-situ stresses' profiles and mechanical property characterization with depth, have been constructed for four vertical wells. The results reveal the swap of stress magnitudes at different mechanical layers, which controls the dimension and orientation of the produced hydro-fractures. Predicted containment of the Hydro-fractures within the specific zones is likely with inevitable high uncertainty when the stress contrast between Sv, SHmax with Shmin respectively as well as Young's modulus and Poisson's Ratio variations cannot be estimated accurately. The uncertainty associated with this analysis is mainly related to the lacking of the calibration of the stress profiles of the 1D MEMs with minifrac and/or XLOT data, and both mechanical and elastic properties with rock mechanic testing results. This study investigates the uncertainty in predicting hydraulic fracture containment due to lacking such calibration, which highlights that a complete suite of data, including calibration of 1D MEMs, is crucial in hydraulic fracture treatment.

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