Hydraulic Fracturing Design Developments Towards Improved Effectiveness in North Kuwait Reservoirs

2021 ◽  
Author(s):  
Zamzam Mohammed Ahmed ◽  
Abrar Mohammed Alostad ◽  
Liu Pei Wu
Keyword(s):  
Hydraulic Fracturing ◽  
High Stress ◽  
Natural Fracture ◽  
Unconventional Reservoirs ◽  
Fiscal Year ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Matrix Acidizing ◽  
Field Development

Abstract The North Kuwait Jurassic Gas (NKJG) reservoirs pose productivity challenges due to their geological heterogeneity, complex tectonic settings, high stress anisotropy, high pore pressure, and high bottom-hole temperature. Additionally, high natural fracture intensity in clustered areas play an important role in the wells hydrocarbon deliverability. These challenges are significant in field development starting from well design and stimulation up to production stages. The Gas Field Development Group (GFDG) are introducing for the first time in Kuwait new completion designs at high fracturing intensity; open-hole Multi Stage Completions (MSC), 4.5" Monobores and hybrid completions along with customized and efficient stimulation methods. This development strategy designed to overcome reservoir difficulties and enhance the well performance during initial testing and long-term production phases. At early stages of production, most of the wells were stimulated with simple matrix acidizing jobs and this method was sufficient to reach commercial production in conventional reservoirs. However, the reservoir depletion trend has negatively affected stimulation effectiveness and the wells performance in the recent years; hence, short and long-term solutions introduced to manage the sub-hydrostatic reservoir pressure. Our current focus is on the short-term stimulation solutions as they are relatively easier to apply compared to the long-term solutions that require additional resources, which are not available in the country. As a result, the stimulation methods, specifically the hydraulic fracturing treatments, increased production dramatically compared to previous years and it applied across North Kuwait Fields in conventional and unconventional reservoirs to reach the production targets of 2020-2021. The hydraulic fracturing treatment designs improved during the 2020-2021 fiscal year. The number of operations tripled compared to before and alternative chemical treatments with new fracturing designs implemented. In addition, these treatments executed across different well completions and reservoir properties. The objectives behind each fracturing treatment were different; for example: discovering new areas, re-stimulating under-performing wells, fracturing unconventional reservoirs, etc. Some promising wells did not flow as per expectation after matrix acidizing treatments despite the logs showing good reservoir quality similar to offset wells with good production. After re-stimulating with acid fracturing, the wells performed much better and one of them set a benchmark as the best producer amongst the offset wells. This paper evaluates the gaps in developing NKJG reservoirs, including fracturing treatments and highlights of the pros/cons for each operation, which in future supports the improvement of stimulation job designs. Moreover, it reveals the future requirements that control the operation success and how to reduce the well cleaning time post-fracturing in the event of low reservoir pressure. Finally, it describes how the outcome of the analyses directly assists reaching the production targets; since NKJG's production mainly depends on stimulation techniques.

Utilizing Pseudo Well Connections to Simulate Multi-Stage Hydraulic Fracturing - Example Based On the Study of a Tight Gas Asset

2021 ◽  
Author(s):  
Aamir Lokhandwala ◽  
Vaibhav Joshi ◽  
Ankit Dutt
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Flow Simulation ◽  
Oil And Gas Industry ◽  
Development Plan ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Field ◽  
Field Development ◽  
Fracture Modeling

Abstract Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

2016 ◽  
Vol 56 (1) ◽  
pp. 225 ◽  
Author(s):  
Kunakorn Pokalai ◽  
David Kulikowski ◽  
Raymond L. Johnson ◽  
Manouchehr Haghighi ◽  
Dennis Cooke
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
High Stress ◽  
Gas Production ◽  
Natural Fracture ◽  
Rock Properties ◽  
Fracture Plane ◽  
Natural Fractures ◽  
Geomechanical Model ◽  
Well Design

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

Reservoir Characterization for Uncertainty Analysis and Its Impact on CO2 Injection and Sequestration in a Depleted Offshore Carbonate Gas Field

2021 ◽  
Author(s):  
Debasis P. Das ◽  
Parimal A. Patil ◽  
Pankaj K. Tiwari ◽  
Renato J Leite ◽  
Raj Deo Tewari
Keyword(s):  
Co2 Storage ◽  
Assessment Process ◽  
Rock Properties ◽  
Co2 Injection ◽  
Storage Site ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Well Integrity ◽  
Seismic Anomalies

Abstract The emerging global climate change policies have necessitated the strategic need for prudent management of produced contaminants and, with cold flaring being no more the best option, Carbon Capture Utilization & Storage (CCUS) technology provides opportunity for development of high CO2 contaminant fields. A typical CO2 sequestration project comprises capturing CO2 by separating from produced hydrocarbons followed by injection of CO2 into deep geological formations for long term storage. While injection ofCO2 may continue over tens of years, the long-term containment needs to be ascertained for thousands of years. Several geological and geophysical factors along with the existingwells need to be evaluated to assess the potential risks for CO2 leakage that maychallenge the long-term containment. This study considers a depleted carbonate field located offshore Sarawak as a possible long-term CO2 storage site. Elements that may lead to possible leakage of CO2over time are the existing faults or fractures, development of new fractures/faults during injection, caprock failure due to pressures exceeding fracture pressure during/after injection and possible leakage through existing wells. The risk assessment process includes identification and mapping of faults and fracture networks, mapping of seals, evaluation of seismic anomalies and gas while drilling records, pore-pressure analysis, laboratory experiments for analyzing changes in geomechanical & geochemical rock properties and well integrity of existing wells. All these parameters are cross correlated, and qualitative risk categorization is carried out to determine the robustness of the reservoir for long term CO2 storage. The evaluation of available data indicates less frequent faulting occur only towards the flank with no seismic anomalies associated with them. Some seismic anomalies are observed at shallower levels, however their impact on the reservoir and overburden integrity is assessed to be minimum. There are four shale dominated formations mapped in the overburden section, which will act as potential seals. Estimated fracture pressures for the potential seals ranges between 6200-9280 psia for the deepest seal to 2910-4290 psia for the shallowest. Therefore,it is interpreted that if the post injection reservoir pressure is kept below the initial reservoir pressure of 4480 psia, it would not hold any threat to the caprock integrity.Leakage rate riskalong the existing wells was determined based on well log data. Well integrity check of legacywells helped identify two abandoned wells for rigorous remediation to restore their integrity. The subsurface risk analysis is critical to ascertain the long-term containment of injectedCO2. The integrated subsurface characterization and well integrity analysis approach adopted in this work can be applied to any other field/reservoir to validate its robustness for long-term CO2 injection and storage.

First Successful Pilot Testing of Unconventional Reservoir in North Kuwait from Scratch to Productivity

2021 ◽  
Author(s):  
Zamzam Mohammed Ahmed ◽  
Abrar Mohammed Salem ◽  
Jose Ramon ◽  
Liu Pei Wu ◽  
Benjamin Mowad
Keyword(s):  
Hydraulic Fracturing ◽  
Particulate Material ◽  
Carbonate Reservoir ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Gas Field ◽  
Field Development ◽  
Creep Effect ◽  
Fracture Closure ◽  
Lab Test

Abstract Jurassic's kerogen shale-carbonate reservoir in North Kuwait is categorized as a source rock exhibiting micro- to Nano Darcy permeability and is Kuwait Oil Company's focus in recent years. Although the challenges are significant (formation creep, fracturing initiation, etc.), the efforts toward producing from unconventional reservoirs and applying experience from both USA and Canada in this field are ongoing. As a step toward development, the gas field development group selected a vertical pilot well to measure the inflow of hydrocarbon from a single fracture while minimizing formation creep (flowing of particulate material and formation into the wellbore that blocks the production). This step was required prior to drilling a long horizontal lateral wells and completing it with multiple hydraulic fractures to confirm commercial production. A comprehensive design process was executed with the full integration of operator and service company competencies to achieve the three main objectives: First, characterize the kerogen rock mechanics which allows selection of the most competent kerogen beds to prevent collapse of the hole during fracturing (creep effect) by conducting scratch, unconfined stress, proppant embedment, and fluid compatibility tests. Then, prepare a suit of strength measurements on full core samples to help in fracturing design and minimize creep effect. The second objective was to design and implement a robust proppant fracturing program that avoids the kerogen concerns after selecting the most competent reservoir unit and suitable proppant type. Third, perform controlled flowback to unload the well and attempt to establish clean inflow unlike previous attempts that failed to either suitably stimulate or prevent solids production (deliver clean inflow). After analyzing the lab test results, choosing the optimal fracturing design, and preparing the vertical well for proppant hydraulic fracturing, the treatment was performed. In December 2019, the hydraulic fracturing treatment with resin-coated bauxite proppant was successfully pumped through 6 ft of perforation interval and followed by a controlled flowback. Resin-coated bauxite proppant was specifically selected to overcome the creep and embedment effects during the fracture closure and flowback. Moreover, a properly designed choke schedule was implemented to balance unloading with a delicate enough drawdown to avoid formation failure. This paper discusses in detail the lab testing, evolution of fracturing design, treatment analysis, and the robust workflow that led to successfully achieving all main objectives, paving the way for long horizontal lateral wells. This unconventional undertaking in Kuwait presents a real challenge. It is a departure from traditional methods, yet it points toward a high upside potential should the appraisal campaign be completed effectively.

scholarly journals WATERFLOOD-INDUCED FRACTURE ON THE INJECTION WELLS IN LOW-PERMEABILITY RESERVOIR OF ACHIMOV SEQUENCE

2018 ◽  
pp. 39-43
Author(s):  
A. V. Klimov-Kayanidi ◽  
R. T. Alimkhanov ◽  
E. S. Agureeva ◽  
R. M. Sabitov
Keyword(s):  
Hydraulic Fracturing ◽  
Low Permeability ◽  
Reservoir Pressure ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Field Development ◽  
Low Permeability Reservoir ◽  
Fracture Formation ◽  
Maintenance Systems

Achimov sequence is characterized by high heterogeneity and low reservoir properties, that makes it impossible economically profitable field development without hydraulic fracturing and usage reservoir pressure maintenance systems. The research aims to develop recommendations for regulating the operations of injection wells, in conditions of waterflood-induced fracture formation. The recommendations can be used to further regulate the waterflooding system for the conditions of Achimov sequence.

Mutual relations between tress drop of induced earthquakes and fault cohesion.

2021 ◽  
Author(s):  
Serge Shapiro
Keyword(s):  
Stress Drop ◽  
Quantitative Characteristic ◽  
High Stress ◽  
Operation Time ◽  
Additional Contribution ◽  
Induced Earthquakes ◽  
Gas Field ◽  
Mutual Relations ◽  
The One

<p>In some regions a significant stress drop characterizes earthquakes induced by underground fluid injections or productions. In addition, long-term fluid operations in the underground can influence a seismogenic reaction of the rock per unit volume of the fluid involved. The seismogenic index is a quantitative characteristic of such a reaction. We derive a relationship between the seismogenic index and the stress drop. We propose a simple and rather general phenomenological model of the stress drop of induced earthquakes. Our model suggests that a high stress drop can result from a decrease in cohesion of initially inactive faults that are seismically activated by long-term fluid operations. On the one hand, the increasing stress drop can lead to an increase in the seismogenic index with the time of fluid operations. On the other hand, a production/injection caused change of the pore pressure can also cause a systematic increase in the stress drop. This can provide an additional contribution to the growth of seismogenic index (and thus to the seismic risk) with operation time of reservoirs.</p><p>The case study of Groningen gas field provides interesting information in this respect. A significant stress drop of some induced earthquakes at Groningen can be explained by activating preexisting cohesive normally-stressed fault systems. Seismic events on such faults lead to the drop of their cohesion due to the rupture process. This cohesion drop contributes directly to the earthquake stress drop. The production-related increase of the differential stress in the reservoir leads to an increasing number of seismically activated more cohesive faults. This leads in turn to an increasing seismogenic index. The seismogenic index seems to be quite low at Groningen. However, it increases systematically with the production time. One of reasons of this behavior can be related to the average cohesion of involved faults as it is mentioned above. An additional effect contributing to this increase is a systematically increasing stress drop due to the production-related pressure depletion increasing the effective stress in the reservoir. A growing seismogenic index can result in an increasing with time maximum possible magnitude, Mmax.</p>

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