Awan, Faisal Ur Rahman (Edith Cowan University, Joondalup, Australia) | Keshavarz, Alireza (Edith Cowan University, Joondalup, Australia) | Akhondzadeh, Hamed (Edith Cowan University, Joondalup, Australia) | Nosrati, Ataollah (Edith Cowan University, Joondalup, Australia) | Al-Anssari, Sarmad (University of Baghdad, Baghdad, Iraq) | Iglauer, Stefan (Edith Cowan University, Joondalup, Australia)
Coal fines are highly prone to be generated in all stages of Coal Seam Gas (CSG) production and development. These detached fines tend to aggregate, contributing to pore throat blockage and permeability reduction. Thus, this work explores the dispersion stability of coal fines in CSG reservoirs and proposes a new additive to be used in the formulation of the hydraulic fracturing fluid to keep the fines dispersed in the fluid. In this work, bituminous coal fines were tested in various suspensions in order to study their dispersion stability. The aggregation behavior of coal fines (dispersed phase) was analyzed in different dispersion mediums, including deionized-water, low and high sodium chloride solutions. Furthermore, the effect of Sodium Dodecyl Benzene Sulfonate (SDBS), an anionic surfactant, on fine aggregation in the suspensions was investigated over a wide alkaline range. At a known pH, the results of stability were validated with the proppant pack glass column test and further verified with microscopic images. It was observed that adding SDBS to the hydraulic fracturing fluid keeps the coal fines well-dispersed in the post-hydraulic fracturing flow back and prevents coal fines aggregation, and ultimately helps permeability enhancement. The results show that at a constant pH, as salinity increases, the zeta-potential (an indirect indicator of stability of the coal-water slurry) reduces. Also, a trace amount of SDBS substantially enhances the dispersion stability of coal fines. This enhancement dictates that coal fines will not congregate and will not plug the proppant pack. Furthermore, the results were confirmed by proppant pack glass-column tests and microscopic images, the result of which illustrate much less aggregation when having SDBS added to the suspension. Polymeric surfactants have been used in the field to disperse coal fines. However, it causes the coal matrix to swell and clog the pore throats, thus reducing the permeability. The anionic surfactant, SDBS, has never been tried in field applications to disperse coal fines. The current research demonstrates the considerable potential of SDBS, as a hydraulic fracturing fluid additive, in enhancing the dispersion stability of the coal fines.
Kindi, Ahmed (Petroleum Development Oman) | Shanfari, Abdul Aziz (Petroleum Development Oman) | Florez Chavez, Juan (Petroleum Development Oman) | Mufarraji, Ahmed (Petroleum Development Oman) | Barhi, Khalfan (Petroleum Development Oman) | Al-Yaqoubi, Mazin (Petroleum Development Oman) | Farsi, Shaima (Petroleum Development Oman)
Petroleum Development Oman (PDO) is currently exploring and developming a number of onshore unconventional deep gas fields for which hydraulic fracturing is playing a key role in proving the commerciality of such reserves. However, stimulating unconventional deep sandstone gas reservoirs with the conventional slick water or crosslinked polymer systems is associated with many challenges. While crosslinked systems frequently cause post-stimulation damage in tight formations (due to the high gel residues in the pores), slick water treatments are, in turn, associated with high surface treating pressures and low-carrying capacity for the high-strength proppants required to withstand the extreme stresses in the deep unconventional formations. In addition, the tightness and high capillary pressures characterizing unconventional reservoirs commonly lead to undesired post-fracturing results, including slow cleanout and poor productivity. The objective of this paper is to describe successful field trials using new fracturing strategy, which was deployed in deep unconventional sandstone gas wells in the Sultanate of Oman. Lineargel fracturing systems combined with high-strength ceramic proppant were utilized to unlock the gas from deep, highly stressed formations with porosity of 3-7% and permeability of 0.1-0.001
Ba Geri, Mohammed (Missouri University of Science and Technology) | Flori, Ralph (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Noles, Jerry (Coil Chem LLC) | Essman, Jacob (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC) | Alkamil, Ethar H. K. (University of Basrah)
Hydraulic fracturing operation requires securing sufficient water resources to access unlocked formations. Successful treatment depends on the fracture fluids that mainly consists of water-based fluid with a low percentage of chemical additives around 1%. Therefore, the oil and gas industry are considered as the largest freshwater consumers by 3 to 6 million gallons of water per well based on a number of fracturing stages. As a result, the traditional water resources from subsurface and surface are getting depleted, and availability of freshwater is becoming more difficult with high cost due to continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 3 to 10 per m3 of freshwater. In addition, transporting process of the raw water to the fracture sites, such as Bakken has an environmental impact, and expensive costs up to USD 5/bbl, while costs of water disposal in range of USD 9/bbl.
This paper aims to study the produced water as alternative water-based fluid with high viscosity friction reducers (HVFR) to reduce environmental footprints and economic costs. To address utilizing produced water as an alternative capable water resource that may use during fracturing treatment, this research presents an experimental investigation associated with using the Permian high-TDS brine water with HVFRs. This work includes experimental research, case studies, and guidelines work on recent improvements on using HVFR to carry proppant and capture the optimum design in fracturing operations. Moreover, the research conducted scaled lab friction measurements that can in turn to be used to improve forecasting of frictions in the field, and therefore of expected surface treating pressures during fracture treatments. Evaluating pipe friction as a function of time to compare HVFRs efficacy in lab and field conditions as well as to predict maximum injection rate during a frac job is investigated.
The outcomes show that high-TDS Permian water with highest dosage of HVFRs had instantaneous pressure reduction effect in 10 seconds while low dosage of HVFRs had lost the effect slowly after 4 min. 30 sec. Also, the results of this study show that the variation of viscosity and pressure reduction at higher shear rate is small. The warm temperature helped rapid polymer dispersion and provided better environment to polymer hydration leads to rapid pressure reduction. Finally, successful implementation in Wlofcamp formation shows that the operation treating pressure reduced from 11,000 to 8,000 psi. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without considering environmental issues.
An abundant supply of low-cost local sands and their associated logistical advantages have incentivized operators over the last couple of years to use them in hydraulic fracturing treatments of unconventional reservoirs. Local sands are known for their low crush strength and high angularity and can contain other mineral particulates, besides quartz, compared to high-quality sands. This paper describes laboratory tests to demonstrate that low-quality sands, when treated with a binder, can generate stable, highly conductive channels within a simulated propped fracture, which could help maximize and also maintain production of hydrocarbons from the reservoir.
Laboratory experiments were conducted to evaluate the performance of local sands when used in aggregate structures, simulating proppant ridges or partial packs formed in a propped fracture. These aggregates were formed by coating sand grains with a binder and placing them in molds to be cured before testing. The sand aggregates were then placed in API conductivity cells to determine the effect of closure stresses on aggregate height, size expansion, binding agent concentrations, and conductivity measurements. Cyclic stress testing was also performed to evaluate the stability of the aggregate structure and conductivity retention of flow channels as the aggregate was subjected to varying stress loads.
The results obtained during this study indicate that the flow capacity of conductive channels prepared from proppant aggregates using local sands is comparable to those prepared using high-quality sand or high-strength manufactured proppant. Fines migration from proppant crushing within the aggregate was observed not to be a concern because sand grains connected and encapsulated by the binder helped lock the crushed sand together. Despite having diminishing permeability within the aggregates, flow capacity of solids-free channels between aggregate masses dominates flow through the propped fracture, making formation of proppant aggregates with high-quality sand or high-strength proppant (HSP) unnecessary.
This suggests that using local sands, despite their low crush resistance, during fracturing treatments can effectively enable well production by forming highly conductive voids or channels on top of the settled sand packs in the propped fractures in a shale reservoir.
Huang, Jiangshui (CNPC USA) | Gong, Wei (CNPC Chuanqing Drilling Engineering Company Ltd) | Lin, Lijun (CNPC USA) | Yin, Congbin (CNPC Chuanqing Drilling Engineering Company Ltd) | Liu, Fuchen (CNPC Engineering Technology R&D Company Ltd) | Zhou, Han (CNPC Chuanqing Drilling Engineering Company Ltd) | Bai, Litao (CNPC USA) | Song, Lulu (CNPC USA) | Yang, Zhengzhou (CNPC Engineering Technology R&D Company Ltd)
Tight oil reservoirs need stimulation in order to produce the trapped oil. The most common form of stimulation used by the oil and gas industry is hydraulic fracturing. Fracturing operations tend to create fractures including primary fractures and microfractures. The objective of this study is to develop a fracturing fluid which can be converted into microproppant, beads, and channelized-proppant as desired in-situ during a fracturing operation to enhance the hydraulic conductivity of the microfractures and the primary fractures, and simplify the hydraulic fracturing operation, where the channelized-proppant is defined as the pillars surrounded by channels.
Resin, curing agents, surfactants, and aqueous phase were mixed together to form O/W emulsion to serve as fracturing fluid. After curing process, resin and curing agent would react and form proppant in-situ. The parameters affect the proppant formation such as the curing temperatures, pressure, mixing strength, surfactant concentration, and size control additives were all studied and thus through controlling the parameters, microproppant, beads, and channelized-proppant can form in-situ as desired. The particle size distribution, sphericity, roundness, conductivity, acid solubility, and crush strength were tested.
Through controlling the experimental parameters and adding size control additives, fracturing fluid can be converted into microproppant, beads, and channelized-proppant as desired at a temperature from 30° C to 90° C. Almost 100% of the resin and the curing agents were converted into proppant with a specific density of 1.09g/ml. For the beads, both the sphericity and roundness are over 0.9, less than 2% fines were generated after being loaded to 15 kpsi, the acid solubility is 2.37%, and the conductivity of the beads of 20/40 mesh tested with proppant loading of 1 lb/ft2 at 4000 psi at room temperature was 227 mD-ft. For the microproppant, both the sphericity and roundness are close to 1 with d50 about 80 µm. Furthermore, channelized-proppant was formed in an artificial fracture with walls made of glass sheets. Thus, with the fracturing fluid developed, the conductivity of the well can be maximally optimized through the in-situ formation of channelized proppant and microproppant to keep the primary fractures and microfractures open respectively.
Ke, Xu (Research Institute of Petroleum E&D(RIPED), PetroChina) | Yongjun, Lu (Research Institute of Petroleum E&D(RIPED), PetroChina) | Xin, Wang (Research Institute of Petroleum E&D(RIPED), PetroChina) | Yang, Shi (Research Institute of Petroleum E&D(RIPED), PetroChina) | Minje, Xu (Research Institute of Petroleum E&D(RIPED), PetroChina) | Xiaohui, Qiu (Research Institute of Petroleum E&D(RIPED), PetroChina)
The early shale gas mining in North America mainly used linear adhesive fracturing fluid, and later, with the deepening of the research and the requirements of component control, the slippery water fracturing fluid system was gradually used. Because of its low viscosity, slippery water can easily communicate micro-cracks and layered seams at different scales, forming a complex volume of network cracks.
Hydraulic fracturing technology has been widely used in oil and gas industry to increase production since 1947. Linear and crosslinked guars are the most commonly used fracturing fluid system. Concerns over damage to conductivity caused by viscous fluids in unconventional reservoirs, the industry has developed an alternative fracturing fluid called slickwater, which consists mainly of water and the low concentration of linear polymer. Slickwater has the characteristic of poor sand carrying capacity, and it is necessary to develop a smart slickwater to improve sand carrying capacity.
The paper introduces a new smart slickwater with high proppant- carrying capability for shale reservoirs. The fluid system consists of linear self-assembled agent, which can improve the viscosity of slickwater at low concentration and maintain a high drag reduction rate. The advantage of the smart slickwater is that only one chemical additive is used, and when the concentration is 0.05%, the drag reduction rate can reach more than 75%, and when the concentration is 0.2%, the proppant ratio can reach 30%, replacing the linear and crosslinked guars.
Laboratory experiments were conducted using the smart slickwater to display excellent static and dynamic sand carrying capacity. The smart slickwater is used in Changqing Oilfield(China), compared with the traditional slickwater, the product is less expensive to use, less water for fracturing, less types and dosage of chemicals required, less equipment needed.
The new smart slickwater with high proppant- carrying capability can change the existing structure of fracturing fluid system.
In unconventional reservoirs, such as Bakken Fm, the stimulation application is the required method to develop and produce economically from this vast reserve. However, the production process is still only through primary depletion mechanism with low recovery factor in ranging of 3-5% due to sharp decline in oil production by depletion in natural fracture networks as well as unsuccessful implementation hydraulic fracturing design. This paper aims to investigate the application of HVFRs with surfactant in high TDS condition to enhance Bakken oil wells production performance using an integral methodology between 3D/2D Pseudo hydraulic fracturing simulator and numerical reservoir simulation. Four types of fracturing fluids as follows: Linear Gel, HVFR-A (mixed with freshwater), HVFR-B (mixed with produced water plus surfactant as additives), and HVFR-C (mixed with produced water) were tested using an integral approach. The workflow in this paper was started by modeling the optimal fracture half-length using 2D/PKN model based on the slurry volume per stage. As a next step, the optimum pump schedule was created using 3D Pseudo hydraulic fracturing simulator. Furthermore, the sensitivity analysis was performed on HVFR-B at different pump rate, final proppant concentration, and proppant size to investigate the proppant transport and production performance. Finally, reservoir simulation tool was utilized to investigate the changing in fracture parameters and evaluating the Bakken oil production. The results showed that HVFRs with surfactant is the optimum hydraulic fracture fluids that showed better performance in proppant transport, which responded by high fracture capability to improve oil production. The findings can be applied and compared to other unconventional shale plays, such as Eagle Ford and Permian Basin.
Unconventional resource development is increasing quickly in many places worldwide. For unconventional resources, multistage completions play a key role for both reservoir performance and well economics, which makes completion optimization a critical technical and commercial decision. This work integrates the reservoir modeling, fracture simulation, production forecast, and synthetic data pool generation via Monte Carlo methods, and it simplifies the final optimization process into a selection from multiple options.
There are many approaches used to optimize completion parameters in shale gas development in the Sichuan basin. Although a trial and error method may work well with an adequate number of wells, this approach is not efficient with few wells because it would take many years to optimize the drilling and completion strategy. Also, such an approach may produce ambiguous results related to high uncertainty due to drilling quality and completion inconsistencies.
An innovative workflow is defined in this work that combines reservoir modeling, fracture network simulation, production matching, regression analysis, and Monte Carlo methods. The procedure begins with modeling of the reservoir using the proper geological environment and reservoir properties. Based on this model, the hydraulic fracture network is simulated with varied compl etion parameter sets, including fluid volume, proppant volume, perforation spacing, and stage spacing. Production forecasting is then performed for each of the fracture network simulations, and the result is matched with previous offset well performance. Regression analysis is used to simplify the relationships between the input (completion parameters) and the output (production results). Finally, based on the regression results, a Monte Carlo method is used to generate a large number of input and output pairs creating a type of synthetic completion choice catalog. This catalog provides a pool of completion options, effectively reducing the optimization process to a choice of the best fit-for-purpose options.
A synthetic model based on Sichuan shale gas is used in this study to validate the workflow on a single- well basis. It successfully produced many synthetic simulation results. With the large number of completion parameters—production result pairs—it is easy to filter the results and identify which combinations are preferred in terms of cost and production. This work also demonstrates that optimization is subject to the definition of purpose and duration of the objectives, which can be used as an important evidence to support different strategies.
Janiczek, Peter (OMV Exploration & Production GmbH) | Dragomir, Alexandru (OMV Petrom SA) | Stojkovski, Jovan (OMV Exploration & Production GmbH) | Makar, Ivan (OMV Exploration & Production GmbH) | Kolasa, Bartlomiej (Halliburton) | Paraschiv, Madalin (Halliburton)
This work presents the entire case history process from the recognition and identification of a potential candidate for multistage hydraulic re-stimulation. This includes operational preparations, execution, and how post-treatment results influenced the rollout of a pilot.
While the recognition of the potential candidate was a coincidence by intersecting a stimulated area from one well to a neighboring well, resulting in sustainable higher production, the study phase to identify the full field potential and candidate well identification was executed in a structured way. A primary challenge was the proper preparation of the well, while keeping the overall costs manageable.
Dedicated supply vessel has been used to accommodate stimulation equipment which was used to execute hydraulic stimulation treatments in Black Sea. Hybrid designs have been designed to carry 20/40 RCP proppant, which was pumped in four cycles. Since reservoir has been accessed by originally opened sleeves with addition of new hydrajet cuts along horizontal section the need of special degradable diverter was required to ensure good lateral coverage and proppant distribution. Together with the treatment, hydrocarbon and water sensitive tracers were pumped, allowing an allocation of flow per cycle. After shutting in the well to allow the resin coated proppant to cure, the well was cleaned out with energized fluid and returned to production
Within four hydraulic re-stimulation cycles, a total of 300 tons of proppant with approximately 2,000 m3 of fluid were pumped and successfully diverted. End of cycle ISIPs rose by more than 20 bars and back-calculation of volume of the diverter stages allowed identifying the diversion effect. During the initial flow phase, very high water cut was observed, exhibiting good cleanup of the treatment. After 2 weeks, the rate stabilized at double the pre-treatment rate and slightly above the conservative prediction.
Multistage hydraulic re-stimulation is not well utilized in Europe thus far and has not been applied offshore. In this mature field, the entire process from study to execution and post-job analysis was strongly cost driven, but resulted in the potential for six more hydraulically stimulated wells in this field.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
The success of hydraulic fracture treatment can be evaluated by measuring fracture conductivity and regained permeability. However, selecting the suitable fracture fluid system plays an essential role to minimize or eliminate the formation damage. To address the potential formation damage during fracturing treatment, this research presents a comprehensive review of a good number of published papers that are carefully reviewed and summarized including experimental research, case studies, and simulation work on recent improvements of using HVFR to carry the proppant and capture the optimum design in fracturing operations. This paper also provides formation damage mechanisms such as chemical, mechanical, biological, and thermal. Moreover, the research explains the fracture damage categories including damage inside fracture and damage inside the reservoir. The advantages of using HVFRs are also fully explained. Experimental rheological characterization was studied to investigate the viscoelastic property of HVFRs on proppant transport. The successful implication of utilizing HVFRs in the Wolfcamp formation, Permian Basin was discussed.
The findings of this research are analyzed to reach conclusions on how HVFRs can be an alternative fracture fluid system of many unconventional reservoirs. Comparing to the traditional hydraulic fracture fluids system, the research shows the many potential advantages that HVFR fluids offer, including superior proppant transport capability, almost 100% retained conductivity, around 30% cost reduction, and logistics, such as minimizing chemicals usage by 50% and operation equipment on location, reduce water consumption by 30%, and environmental benefits. Finally, this comprehensive review addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.