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Results
Abstract This paper describes methods to alter the flow path in the open annulus section of a horizontal Granite Wash stimulation completion. The challenge was to complete a 1,600-ft open annulus section using standard plug and perf (P&P) stimulation methods. The objective was to isolate and initiate individual fractures at each stage in an open annulus environment. Altering the flow of proppant and fluid in the open annulus and near wellbore (NWB) involved multiple products, and procedures. This included cyclic application of the following: Pump rates and intra stage shut-ins. Fluid types and viscosity-alteration (friction reducer and crosslinker). Proppant slurry and clean fluid sweep stages. Solid diverters. Chemical surface modification agents (SMAs) and resin-coated proppant (RCP). The objectives were to cycle the bottomhole treating pressure (BHTP) and alter the flow path in the wellbore, annulus, NWB, and far field, while maintaining annulus and casing integrity. A cyclic but continuous bottomhole pressure (BHP) increase was observed throughout the four stimulation stages pumped in the open annulus section. The surface pressure characteristic signature changed after each shut-in. Perforation operations in the open annulus sections above a completed stage did not indicate proppant inflow through the new perforations. The drill out of plugs in the open annulus section circulated trace amounts of untreated proppant. Initial flow back operations showed minimal proppant flowing to surface. Strong production results indicate contribution from 40% of the lateral section that had no annular isolation. Normalized production is compared to adjacent offset. Our use of an enhanced cyclic diversion process (ECDP) was a success. Instead of using a single product or process; we used a cyclic combination of solid diverters, proppant coatings, prop/sweep stages, and shut-ins to deliver a variable BHTP and altered flow paths.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
Abstract Understanding the dynamic process of fluid invasion and flowback has significant technological implications in developing shale plays. One of the physical models used to study this process is coreflooding, which mimics the process of fracturing fluid invasion, flowback, and hydrocarbon recovery from shale formations. However, coreflooding is time consuming, expensive, and unable to provide insights to the underlying physics at the pore scale level in most instances. Rock-on-a Chip (ROC), based on microfluidic technology, is an emerging approach that provides a new method to study fracturing fluid invasion and flowback affected by the petrophysical properties using direct visualization and measurement. In this study, the porous matrix, representing shale formations, and single large channel, representing hydraulic fractures or natural fractures, were defined in an oil-wet microfluidic chip; the drainage-imbibition cycles that are analogous to fracturing fluid invasion and subsequent flowback were measured by optical microscopy. Specifically, the effect of interfacial tension and fracture patterns ("half" fracture and "S" fracture) on the fluid invasion factor and flowback efficiency was examined. The results show that the invasion factor and flowback efficiency correlated well with the capillary pressure of fracturing fluids. In addition, model fractures have a major effect on the flowback. In particular, the invasion factor and flowback efficiency of the water-based fracturing fluids were significantly impaired in the "S" fracture pattern, as compared to homogeneous and half fracture patterns. Notably, by improving fluid mobility between the porous matrix and fractures, the addition of a surfactant to the fracturing fluids significantly enhanced the fluid invasion and flowback in all of the fracture patterns. The results demonstrate that the ROC model proposed in this work can be used to study the flowback process affected by properties such as wettability, permeability, initial water saturation, and reservoir pressure. Consequently, it has potential for guiding water management and chemical treatment in hydraulic fracturing.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- 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)
- (21 more...)
Abstract Research and development of hydraulic fracturing plug materials has shifted to materials that degrade upon exposure to wellbore fluids, thus eliminating the typically necessary post-fracturing millout operations. This paper provides an overview of the field trials and initial commercialization of a dissolvable metal alloy fracturing plug in the Williston Basin. The paper also discusses the alloy’s reaction with wellbore fluids and degradation prediction based on wellbore fluid constituents. During several months of degradable fracturing plug field trials, performance metrics were established, monitored, and analyzed for each stage of the completion process. Tests were conducted using samples of the alloy submerged in actual wellbore fluids from a given field trial to predict wellbore degradation. The test results were correlated to the field trial results, which helped enable prediction of degradation in future field trials. The conventional design and mechanics of the degradable alloy fracturing plug allow it to be set similar to the industry-standard composite plugs because no special tools or processes are necessary. More than 1,500 successful runs have been completed in the Williston Basin alone. Installation performance has been predictable since the field trials began; however, estimating degradation time has been more challenging because fluid-related variables are difficult to control. Degradation can vary significantly, even in similar fluids, because of specific fluid constituents’ effects on the reaction that occurs at the plug-fluid interface. The approach of relating test results to field results helps correlate many of these variables and helps identify specific constituents that affect degradation. Strong production figures allowed an operator to skip post-fracturing treatment millout operations in a few cases, thus saving more than USD 200,000 and several days of millout operations in one particular case. Additional field results and tests should help predict with a higher degree of certainty whether a well can be put on production after the fracturing treatment. This paper summarizes an approach for establishing performance standards, implementing testing methods, and predicting degradation of a degradable alloy fracturing plug designed to help eliminate post-fracturing treatment interventions altogether.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- (3 more...)
- North America > United States > West Virginia > Walton Field (0.93)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.89)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.89)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.89)
Abstract Success of a matrix acidizing or fracture stimulation treatment depends upon complete coverage of all zones. The diversion process is used to help ensure that stimulation fluids are distributed across the entire interval to be treated. The diversion method best suited for a particular situation depends on many factors, including the type of well completion, perforation pattern, zonal isolation method, and stimulation technique. Selection of the most appropriate diversion method is also influenced by variations in formation permeability or stress contrasts along the interval to be treated. The purpose of this paper is to provide a historical review of diversion technologies applied in matrix acidizing and hydraulic fracturing treatments and to build upon past experiences to allow optimization of modern diversion practices with self-degrading particulates. Diverter design guidelines will be provided guiding the reader toward the best practices for a) choosing the appropriate base material, b) selecting the correct particle size distribution, c) deploying the diverting agent properly, and d) monitoring the execution of the diverter stages. Laboratory and field data will be provided to supplement the design process.
- North America > Canada (1.00)
- North America > United States > North Dakota (0.96)
- Europe (0.93)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > Montana > Williston Basin (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/13 > Halfdan Field > Maastrichtian Formation (0.99)
- (5 more...)
Abstract Plug and Abandonment, P&A, operation is inevitable for each and every well. Most oil and gas wells are plugged at lowest cost possible complying with requirements set by regulatory agencies. Geopolymers can be used as an alternative material for P&A operations. Unlike many other alternatives such as resin, they are cost efficient and easy to pump down the wellbore. They can be mixed easily onsite and activated by addition of an alkali activator. The research presented in this paper shows they can have a good pumpability, low shrinkage, and high compressive and shear bond strength. The Geopolymer mixtures in this work were composed of Class F Fly Ash rich in Silicate and Aluminum, with elements of Potassium, Calcium, Iron, Sodium, and Titanium. A mixture of Sodium Hydroxide and Sodium Silicate was used to activate the Fly Ash mixtures. Geopolymer mixture designs tested in this work showed high compressive strength, low shrinkage, and suitable thickening time for applications in well abandonment. In addition, these alternative P&A materials can be produced cheaper with less environmental impact, which is a proper fit in the applications oil and gas well cementing.
- Geology > Geological Subdiscipline > Geomechanics (0.71)
- Geology > Mineral > Silicate (0.46)
Abstract Ensuring effective production benchmarking studies and field management requires a through and continuing understanding of the reservoir performance. Deviations from anticipated performance must be recognized and, if necessary, corrected before they impact the expected life cycle performance and value of the project. This study was performed to establish (Inflow Performance Relationship) IPR risked modeling for a variety of completion options and to assess the likely well performance under gas lift production benchmarking of a field. The IPR risked inflow modeling used the Monte Carlo simulation method to define the range of potential outcomes associated with uncertainties in key reservoir and completion input data. Skin data for the completion options being considered, i.e., Open Hole Gravel Pack (OHGP), Cased Hole Frac-Pack (CHFP) and Cased Hole Gravel Pack/Internal Gravel Pack (CHGP/IGP) were then used to establish the probabilistic distribution, which could then be used in combination with reservoir uncertainty data to perform the risk-based inflow modeling. The results of the risk-based IPR modeling showed that the completion options for the CHFP proved to be the best overall performer. The CHGP/IGP completion proved to be the least effective, primarily because of the high skin associated with this type of completion. The OHGP completion compared closely to the CHFP, but the greater probability of higher skin resulted in poorer performance compared to the CHFP. Tornado analysis was carried out to highlight the parameter leading to the greatest uncertainty in well performance. This analysis proved that permeability, in most cases, had greater negative impact on well performance than skin when there was a higher permeability layer in the reservoir. It should be noted that this can reverse; skin can be the most significant negative factor for lower permeability ranges. In all cases, skin had the greatest positive impact on well performance due to negative values of skin for all completion types. To validate the model, well test data was used to validate the probabilistic skin model results for CHFP completion. The gas lift modeling was carried out based on IPR Risked inflow modeling to reduce the gas lift design uncertainties for vertical and deviated wells. Gas lift was extremely beneficial in the lower productivity index (PI) or higher water cut (WC) wells. Impact of gas injection depth on oil production was assessed for each reservoir layer at various stages of the field life.
Abstract Production logs from horizontal wells in shale reservoirs indicate that more than 30% of the perforation clusters do not contribute to production. One major reason is recognized as the stress shadow effect which impedes the propagation of the interior fractures within a single fracture stage. Although limited entry perforations have been successfully introduced in horizontal wells to counteract this completion inefficiency, the complex mechanisms involved have not been fully understood. In this paper, a fully integrated workflow that incorporates fracture propagation, reservoir flow and wellbore hydraulics has been developed to evaluate the efficiency of limited entry perforations during multiple simultaneous fracture propagation. Darcy–Weisbach and classic orifice flow equations are adopted to describe the wellbore and perforation friction. The coupled reservoir and geomechanics model are solved by finite element code while a cohesive zone model, which accounts for the significant non-linear effects near fracture tip over the conventional linear elastic fracture mechanics, is used to simulate the fracturing process. During the stimulation of multiple fractures, uneven fluid distribution will be observed once the fractures begin to interfere with each other. Meantime, the difference in perforation pressure loss due to uneven fluid rates will counteract the stress shadow effects and balance fluid distribution. Thus, a larger perforation friction coefficient is favorable but it also causes higher pumping pressure. A novel proppant model is proposed to represent both stress- and time-dependent fracture conductivity change due to proppant degradation in subsequent long-term production. Production simulation results demonstrate that deliberate deployment of limited entry technique can significantly increase production but this benefit is reduced with increased cluster spacing. Sensitivity study indicates that better well performance could be obtained by reducing number of shots in each cluster and increasing number of clusters in each stage. Non-uniform perforation shots distribution is proven to be an effective means to counteract the stress shadow effects while the cluster length is unchanged. Simulation results also indicate how the heterogeneity in reservoir properties affects the performance of limited entry perforations. The proposed workflow has the advantage to integrate fracturing and production simulation in the same grid system and evaluate performance of different stimulation strategies. The comparison studies can provide critical insights to the application of engineered limited entry.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Field > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Field > Montney Formation (0.99)
Abstract This literature review summarizes the theory and application of chelating agents in acidizing both carbonate and sandstone formations, and in hydraulic fracturing. The objective of this work is to explain the key role that chelating agents play in stimulation. This paper reviews results that were obtained through various laboratory tests, which aid in understanding chelating agent interactions with formation rock and fluids. Results were obtained through the following tests: coreflooding, corrosion tests, compatibility, Inductively Coupled Plasma (ICP), Environmental Scanning Electron Microscope (ESEM) and X-Ray Diffraction (XRD). At high temperatures, conventional acids such as HCl show severe corrosion, lack of penetration and sludging characteristics. Several organic acids were proposed in the reviewed literature to solve these issues. However, even organic acids result in solubility and incompatibility issues. Based on these shortcomings, chelating agents are often used and show good dissolving power, low corrosion, low sludging tendencies, excellent iron control, and some are highly degradable and environmentally friendly. In addition to acidizing, chelating agents allow for the application of saline water fracturing because of their water-softening properties. They also contribute to high-temperature water fracturing through delayed chelation of both the crosslinker and breaker. This work summarizes the applications of chelating agents in the stimulation sector. Over 100 papers were reviewed, including the latest developments and field applications of this technology. Readers can easily expand on this paper to further explore the wide range of applications chelating agents can offer the oil and gas industry.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia > Middle East (1.00)
- Africa (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Abstract Cement fluid loss can cause loss of cement quality and its functionality. A common cement system with fluid loss problems is a system containing weighting agents. Barite, which is used in cement to increase the slurry weight, is one example. In this paper, the effect of barite nanoparticles (NPs) in different concentrations on cement fluid loss was investigated. Barite NPs were generated via dry grinding method using a high-energy ball grinder. The barite NPs were added to the cement slurry in various concentrations, and a low pressure low temperature (LPLT) static fluid loss tester was used to measure the cement fluid loss in the laboratory. It was observed that, as the nanoparticles concentration increases from 0 to 5 percent by weight of total slurry, the average fluid loss decreases by about half. Results showed that about 50 percent filtration reduction can be achieved by replacing 3% weight of normal barite with barite NPs in the cement slurry. The experimental tests presented herein also show the effect the fluid loss has on cement thickening time, clearly identifying that the cementing fluid loss must be integrated into the design of the cementing operation design and pumping schedule. It verified that adding barite NPs to cement slurry is promising from both a technical and cost saving perspective. The novelty of this research is in the application of barite NPs at low concentrations to reduce cement fluid loss significantly. Reducing the cement fluid loss can prevent many problems such as low quality cement due to poor crystallization, high equivalent circulation density (ECD), which results in formation failure during cementing jobs. The results presented herein also show a significant fluid loss effect on the cement thickening time. Lower cement thickening time seen due to fluid losses to the formation can cause the cement to set before completing cement placement, fluid channeling between the cement and formation, and low compressive strength cement.
In-Situ Poisson's Ratio Determination under Different Deformational Conditions
Baldino, S.. (Tulsa University Drilling Research Projects, McDougall School of Petroleum Engineering, University of Tulsa) | Rafieepour, S.. (Tulsa University Drilling Research Projects, McDougall School of Petroleum Engineering, University of Tulsa) | Miska, S. Z. (Tulsa University Drilling Research Projects, McDougall School of Petroleum Engineering, University of Tulsa)
Abstract Knowledge of in-situ mechanical rock properties is of critical importance for well design and prediction of formation fracturing, including human-induced seismicity. Shahri and Miska (2013) proposed an innovative technique for the estimation of in situ Poisson's ratio. Under the assumption of plane strain, the interference well test was generalized to also find the average in-situ Poisson's ratio. An extension and comparison of this model to several different boundary conditions such as generalized plane stress and uniaxial strain is proposed. Firstly, the three-dimensional theory of consolidation is applied to formulate the generalized diffusivity equation for a deformable porous medium. This provides us with the coupling between deformation and flow response needed to determine Poisson's ratio from an interference well test. Generalized plane stress, simplified generalized plane stress, uniaxial strain, generalized uniaxial strain, and plane strain with constant horizontal stress assumptions are then applied, resulting in several different values of the estimated Poisson's ratio. The same field data originally analyzed are used to show the main steps of the proposed technique, and to compare its results with that derived in the earlier work. Estimation of average in situ Poisson's ratio, using different assumptions, provides a means to select the most appropriate model for accurate reservoir deformational behavior. In-situ Poisson's ratio and specific storage capacity, depending on flow-induced stress changes, can also enhance the accuracy of the estimated stress distribution resulting from production/injection. This leads to optimization of well design and formation fracturing.
- North America > United States > Oklahoma (0.28)
- Asia > Middle East > Iran (0.28)
- Research Report (0.46)
- Overview > Innovation (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)