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Collaborating Authors
Fracturing materials (fluids, proppant)
The presentation reviews the results of taking three 40/70 mesh proppants commonly used for multi-stage horizontal well slickwater completions in North America and testing them at 0.5 lb/ft2 over 1000 hours of "extended time" at stress and temperature conditions representative of the Bakken formation of North Dakota. The results presented give a clear insight into the degree of damage occurring in the reservoir due to time at stress and temperature.
- North America > Canada > Saskatchewan > Williston Basin > Bakken Shale Formation (0.99)
- North America > Canada > Manitoba > Williston Basin > Bakken Shale Formation (0.99)
The most important data for designing a fracture treatment are the in-situ stress profile, formation permeability, fluid-loss characteristics, total fluid volume pumped,propping agent type and amount, pad volume, fracture-fluid viscosity, injection rate, and formation modulus. It is very important to quantify the in-situ stress profile and the permeability profile of the zone to be stimulated, plus the layers of rock above and below the target zone that will influence fracture height growth. There is a structured method that should be followed to design, optimize, execute, evaluate, and reoptimize the fracture treatments in any reservoir. The first step is always the construction of a complete and accurate data set.Table 1 lists the sources for the data required to run fracture propagation and reservoir models. The design engineer must be capable of analyzing logs, cores, production data, and well-test data and be capable of digging through well files to obtain all the information needed to design and evaluate the well that is to be hydraulically fracture treated.
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.92)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
In-Basin Sand Performance in the Permian Basin and the Case for Northern White Sand
Malone, M. R. (New Auburn Energy Management, LLC., Houston, TX, United States of America) | Bazan, L. W. (Bazan Consulting, Inc., Houston, TX, United States of America) | Eckart, M. J. (Bazan Consulting, Inc., Houston, TX, United States of America)
Abstract Proppant selection, and the resulting dimensionless fracture conductivity, impacts well performance. Proppant quality standards were developed to quantify proppant performance using dimensionless fracture conductivity, correlating the flow potential of the propped fracture relative to the formation. Since 2018, there has been a near complete switch to in-basin sand (IBS) for completing oil and gas wells in the Permian Basin. The switch to IBS has primarily been based on the idea that overall well and field economics are improved because: 1) capital costs are lowered by sourcing sand locally reducing costs and logistics, and 2) well results using IBS were "good enough" in terms of well performance justifying the use of inferior proppants. Little regard is given to the long-term production impacts, field development value and cumulative free cash flow over a five-to-ten-year horizon. Rystad Energy (2022) evaluated 850 wells from seven operators in both the Midland and Delaware basins and provided clear evidence that the perceived benefits of using IBS to complete Wolfcamp A (WCA) wells in the Permian is not accurate. The Rystad Energy studies will be reviewed in detail. This manuscript presents extensive hydraulic fracture modeling and production simulations of the WCA formation for both the Delaware and Midland basins using 100- and 40/70-mesh to identify the conductivity difference between IBS and NWS to provide an engineering basis for the Rystad Energy results. Conductivity differences for each mesh and sand type ultimately allowed a comparison of well production and net cash flow for P50 wells. The WCA production forecast cases were calibrated to the published Rystad Energy data, where possible, and EUR values. The payout, cumulative production differences and net cash flow are presented comparing IBS and NWS materials. Comparing results between NWS and IBS provides an engineering basis that NWS characteristics drive superior well performance in the Permian basin. As fracture conductivity increases, either from using NWS material or larger mesh sizes, the well production also increases over time. This is also the general conclusion from the Rystad study. This work demonstrates that NWS, while more expensive upfront, performs better throughout the well life, and is almost always the better economic choice and shows a long-term benefit using NWS. Utilizing IBS in the Permian basin results in suboptimal cashflow and reduced long-term profitability. The well performance using IBS is expected to progressively worsen over time. This work demonstrates fractures in the Permian basin are conductivity limited and using IBS negatively affects cash flow and long term well deliverability. NWS is a superior product to IBS and generates enhanced fracture conductivity and production in the Delaware and Midland basins.
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Mineral (0.46)
- North America > United States > Texas > Permian Basin > Midland Basin > Wolfcamp A Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.94)
- (26 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics (1.00)
Abstract Hydraulic fractures tend to propagate in a plane that is perpendicular to the least principal stress. As a result, unconventional oil and gas wells are typically drilled in the direction of minimum horizontal stress (Shmin) to maximize drainage area. However, in some regions, due to acreage constraints, wells are drilled to maximize the number of wells instead of the ideal orientation with respect to subsurface stresses. We studied the impact of changing well orientation on well productivity in the Bakken Play by simulating a wide range of operational scenarios including proppant loading, well spacing, cluster spacing, and depletion. Our simulation results were compared to historical Bakken well performance data filtered based on the same well orientations and completion designs. The simulation results show that drilling wells parallel to Shmin maximizes well productivity, consistent with the reported actual data. However, the degree of production uplift in actual data cannot be fully attributed to well orientation. We demonstrate that job size, depletion, cluster spacing, and well spacing all affect the impact of well orientation on performance. It is challenging to rigorously quantify the effect of well orientation versus completion design on well productivity in historical data. Simulation studies help to determine the impact of each parameter, helping operators optimize their development strategy. Simulation sensitivity analyses show that depletion, wider cluster spacing, and wider well spacing can lessen the effect of well orientation on well productivity.
- North America > United States > North Dakota (0.49)
- North America > United States > South Dakota (0.35)
- North America > United States > Montana (0.35)
- (2 more...)
- Research Report > Experimental Study (0.49)
- Research Report > New Finding (0.49)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.98)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract The use of synthetic high viscosity friction reducers (HVFRs) has become common practice in hydraulic fracturing as a reliable method for delivering proppant into target formations. HVFRs address many of the challenges that are present when using cross-linked or linear gels and provide reliable performance across a wide range of water qualities. Despite these advantages, HVFRs present their own difficulties that must be addressed. The use of oxidizing or enzymatic breakers is essential when cross-linked gels are used for proppant transport to reduce the fluid's viscosity to a point where formation pressure is sufficient to allow the well to produce, and to minimize formation damage. While HVFRs are not nearly as viscous as cross-linked gels, they have sufficient molecular weight and are viscous enough, and persistent enough, to negatively impact flowback when a well is brought online. Moreover, it has been found that synthetic polymers can also cause serious formation damage similar to or worse than gel-based systems resulting in negative effects on the well's production. As a result, breakers are also commonly used in conjunction with HVFRs to maximize production of the well after stimulation is complete. It is difficult to know if these treatments are effective, however, and are largely guided by prior experience. Such reliance can be dangerous, however, given that HVFRs can comprise a wide range of chemical compositions, molecular weights, and physical forms. We believe a more systematic study of breaker effects on HVFRs is warranted to develop a better understanding of how combinations of breakers and HVFRs should be applied in field operations. Here we will discuss a series of laboratory investigations conducted to understand how different types of HVFRs respond to treatment with various breakers. The breakers selected are chemically distinct and may operate via different mechanisms (e.g., oxidative, non-oxidative), or on different timescales (e.g., instantaneous, slow release). Likewise, the HVFRs are comprised of distinct polymer backbones, and thus we anticipate will behave differently when exposed to the breakers. Indeed, significant differences in viscosity reduction behavior are observed depending on the HVFR-breaker pairing, concentrations of the two components, and test temperature. Some findings were unsurprising, such as the broad applicability and rapid response of instantaneous oxidative breakers, while others were not, such as the relatively selective and temperature-dependent response of non-oxidative breakers. Such a diversity of breaker chemistries and response behavior may initially seem overwhelming for completion engineers designing a stimulation pump schedule. However, we believe that this diversity may, in fact, present an opportunity for more nuanced treatments (i.e., break profiles) through judicious selection and application of breaker and HVFR combinations, all within the context of a well's characteristic temperature and water chemistry.
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Production and Well Operations (1.00)
Abstract This paper documents the results of diagnostic tests in a well that was equipped with measuring devices for analyzing pressure and acoustic behavior during multistage fracturing treatments. This well was also surveyed by an ultrasonic device for measuring the entry hole sizes of treated and untreated perforations. Well and treatment design parameters selected for scrutiny included cluster perforation density and the circumferential phase angle of entry holes with respect to elevation. Perforation erosional analysis was performed on each frac stage of the diagnostic wells by comparing perforation sizes of treated perforations with intentionally untreated perforations to estimate the eroded area for each perforation, then applying a two-component erosion model to allocate proppant among all the clusters for that frac stage. The allocated proppant was then used to compute treatment uniformity and compared with allocation and uniformity values determined by the DAS provider. This unique dataset was used to perform five categories of analyses: pipe/casing friction pressure, step down testing, perforation entry hole erosion, treating pressure, and inter-cluster proppant allocation and uniformity. Determination of perforation entry-hole erosion parameters are shown to have diagnostic value in assessing treatment confinement and identifying deviations from standard erosion theory. The impact of variable and uncertain initial (untreated) entry hole sizes is shown to adversely impact the accuracy of both DAS and erosion-based proppant allocation routines. Evidence is provided quantifying the negative effect of proppant separating from the fluid stream due to inertia on the accuracy of treatment distribution provided by DAS interpretation.
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
Abstract Delivery of the proppant required for a hydraulic fracturing job can quickly become a weak link in operational excellence. New technology in the oil and gas industry has been hyper focused on well site efficiency but has missed out on the synergies that can be leveraged between proppant delivery and hydraulic fracturing operations. A new logistics solution was developed to take advantage of these synergies and support higher operational efficiency. The new proppant logistics solution was built on an established hydraulic fracturing field data collection platform. Driver and proppant load information was ingested into the new solution with a software program used to order the proppant loads to be delivered to the job. The combination of these two systems synergized the new solution and ensured the supply chain of products needed for a hydraulic fracturing job would not create a weak link in the chain of operational excellence. With the world still feeling impacts from the 2020 pandemic, worldwide shipping and logistics markets sank into a supply imbalance. This supply-demand disparity combined with the consistency of over-the-road trucking as compared with the historically volatile nature of proppant delivery, over-the-road trucking became very desirable for existing proppant delivery drivers. This paper will present a case study reviewing how a new software solution was built and implemented to facilitate rapid field data delivery and will also discuss how this solution was utilized to build out differential visual and predictive analysis tools to promote timely delivery of proppant needed at each fracturing location. After implementing the new solution, success was measured through the following observations. 90% decrease in proppant delivery downtime. 35% decrease in drivers needed for a job, lowering the footprint of drivers on the road. Individual drivers delivered 20% more loads per day. 33% decrease in total time required to deliver a load of proppant. Enhanced competitiveness among drivers lowering the cost to produce a barrel of oil. With this new solution, proppant logistics teams are now able to leverage intelligent solutions to help dispatch proppant so that operational excellence is maintained to the highest standard.
- Information Technology > Data Science (0.93)
- Information Technology > Software (0.68)
- Information Technology > Architecture > Real Time Systems (0.33)
Engineering a Synthetic Friction Reducer to Combat Undesirable Formation of FR-Metal Complex/Precipitation in Slickwater Fracturing
Sun, Hong (Solvay, The Woodlands, TX, USA) | Lin, Ying-ying (Solvay, The Woodlands, TX, USA) | Geng, Xi (Solvay, The Woodlands, TX, USA) | Wickramasinghe, Lanka (Solvay, The Woodlands, TX, USA) | Zalluhoglu, Fulya (Solvay, The Woodlands, TX, USA) | Wang, Qing (Solvay, The Woodlands, TX, USA)
Abstract During stimulation and production, a highly viscous and rubbery precipitation can form due to incompatibility of friction reducer polymers (cationic, anionic or amphoteric) with ferric ions, particularly in formations with high iron content. This material plugs up proppant packs, even production strings, and is extremely detrimental to well productivity. A straightforward sequestration approach with chelants does not work because of poor outcome and prohibitive economics. Compatible biopolymer FRs, as an alternative approach, have limited applications due to their moderate FR performance compared to synthetic PAM based polymers. This work shows the development of a novel synthetic friction reducer to address this challenge. The polymer was designed by systematically optimizing monomer compositions, molecular weight and surfactant packages. Friction reduction performance of the newly developed FR was evaluated in friction loops under various water conditions. Iron tolerance tests were performed by mixing ferric iron with prehydrated FRs under different pHs, at high concentrations, and salinities. The mixture solutions were then placed in a water bath for heat treatment to simulate downhole conditions and to accelerate the formation of the ferric/FR complexes. Comparative experiments were performed using conventional FRs. In order to probe the interaction between polymers and the iron species, zeta potential analyzer was applied to measure charge changes of the polymer strands. The newly developed FR showed superior FR performance with fast hydration and high overall friction reduction, in both fresh water and synthetic brines. In iron tolerance tests, rubbery precipitations formed in solutions for all three types of conventional FRs, while no such precipitations were observed with the newly developed FR, even in the presence of 500 ppm ferric ion. This test was repeated in a wide range of pH and salinity conditions and no significant viscosity change of the FR polymer solution was observed before and after the test. Zeta potential measurements confirmed the validity of the polymer design to minimize the interaction between the new FR polymer and iron ions. This paper demonstrates that the newly developed friction reducer successfully solves the incompatibility issue of FRs with iron spices, i.e., without flocculation on the surface or formation of gummy precipitations downhole. Its superior friction reduction performance with no concerns of potential damages make it a strong candidate for iron-rich fields. Mechanism of the interaction between iron and synthetic polymers is proposed and confirmed by zeta potential results. The manuscript discusses in depth the strategy of the design of the newly developed copolymer, including selection of monomers, molecular weight control, and inverting surfactants.
- North America > United States > Texas (0.69)
- North America > United States > Oklahoma (0.47)
- North America > Canada > Alberta > Stettler County No. 6 (0.24)
- (3 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.35)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well Intervention (1.00)
Practical Optimization of Perforation Design with a General Correlation for Proppant and Slurry Transport from the Wellbore
Dontsov, Egor (ResFrac Corporation, Palo Alto, CA, USA) | Ponners, Christopher (ResFrac Corporation, Palo Alto, CA, USA) | Torbert, Kevin (Cornerstone Engineering, Inc., Bakersfield, CA, USA) | McClure, Mark (ResFrac Corporation, Palo Alto, CA, USA)
Abstract During plug and perf completion, perforation pressure drop is used to encourage a uniform distribution of flow between clusters by overcoming stress shadowing, stress variability, and nonuniform breakdown pressure. However, proppant inertia, gravitational settling, and perforation erosion contribute to nonuniformity, even with an aggressive limited-entry design. In prior work, Dontsov (2023) developed a correlation for predicting proppant outflow from the wellbore as a function of slurry velocity, perforation phasing, and other parameters. In the present study, the Dontsov (2023) correlation is integrated into a wellbore dynamics simulator capturing key physical processes that control slurry and proppant outflow from the wellbore, such as erosion, stress shadowing, and near-wellbore tortuosity. The simulator is fast running and incorporated into a tool for Monte Carlo uncertainty quantification and design optimization. First, we run a series of sensitivity analysis simulations to evaluate the effect of key model inputs. The simulations demonstrate processes that can cause heel bias, toe bias, or heel/toe bias in the erosion distribution. Next, we apply the tool to analyze field datasets from the Eagle Ford and the Montney. Downhole imaging of erosion data enables model calibration. Calibration is necessary because differences in casing, cement, and formation properties cause differences in erosion behavior and flow distribution. Parameters controlling the magnitude of erosion and stress shadow are modified to match the trends observed from the downhole imaging. After calibration is performed, the model is applied to maximize the uniformity of proppant placement by optimizing perforation phasing, diameter, count, and cluster spacing.
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.55)
- Geophysics > Borehole Geophysics (0.55)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)