Friction reducers (FRs) represent an essential component in any slickwater-fracturing fluid. Although the majority of previous research on these fluids has focused on evaluating the friction-reduction performance of chemical components, only a few studies have addressed the potential damage these chemicals can cause to the formation. Because of the polymeric nature of these chemicals—typically polyacrylamide (PAM)—an FR can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. The present study introduces a new FR that replaces the linear gel with an enhanced proppant-carrying capacity and reduced potential for formation damage.
Friction-reduction performance, proppant settling, breakability, and coreflood experiments using tight sandstone cores at 150°F were conducted to investigate a new FR (FR1). The performance of the new FR was compared with two different FRs: a salt-tolerant polymer that is a copolymer of acrylamide and acrylamido-methylpropane sulfonate (FR2), and a guar-based polymer (FR3). Different breakers were used to examine the breakability of the three FRs, including ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (HP), and sodium bromate (SB).
The friction reduction of the new chemical was higher than 70% in fresh water or 2 wt% potassium chloride (KCl) in the presence of calcium chloride (CaCl2) or choline chloride. The presence of 1 lbm/1,000 gal of different types of breakers did not affect the frictionreduction performance. The friction reduction of 1 gal/1,000 gal of the new FR1 was also higher than that of the guar-based FR3 at a load of 4 gal/1,000 gal at the same conditions. The results show that the new FR is breakable with any of the tested breakers. Among the four tested breakers, APS is the most-efficient breaker. Static and dynamic proppant-settling tests further indicated a superior performance of FR1 for proppant suspension compared with a PAM FR (FR2). Coreflood experiments showed that FR1 did not cause any residual damage to the core permeability when APS was used as a breaker, compared with 10% and 9% damage when FR2 and FR3 were tested, respectively. Coreflood tests also showed that FR1 is breakable using SB with only 2.5% damage, whereas FR2 and FR3 resulted in 47% and 41% damage, respectively. The results also show that higher salinity does not affect the breakability of the new FR.
The proposed FR shows higher friction-reduction performance and better proppant-carrying capacity with no formation damage, compared with the conventional counterparts. Hence, FR1 is a viable choice for application in fracturing formations with proppants.
This paper introduces a new approach for studying productivity-index (PI) behavior of fractured oil and gas reservoirs during transient- and pseudosteady-state conditions. This approach focuses on the fact that PI derivative could vanish at a certain production time, indicating the beginning of pseudosteady state, wherein the PI demonstrates constant value. The reservoirs in this study are considered depleted by horizontal wells intersecting multiple hydraulic fractures where Darcy flow and non-Darcy flow may control flow patterns in the porous media. The PI is calculated assuming constant production rate and considering pressure profile for early- and intermediate-production time when transient condition dominates fluid flow and late-production time when pseudosteady state is reached.
The outcomes of this study can be summarized as understanding PI behavior at early- and intermediate-production time when transient flow is dominant in the porous media and late-production time when pseudosteady-state condition is reached; indicating the effect of reservoir configuration on PI and the time when this index approaches constant value; and introducing a study for the influence of non-Darcy flow in the PI.
The most-interesting points in this study are the following. First, that PI reaches constant value when the rates of change with time for the two pressure drops--transient and pseudosteady state--are equal. Second, the time for approaching constant PI in a small drainage area is faster than for a large area. Third, that PI is affected by non-Darcy flow at early- and intermediate-production time; however, the effect is not seen at late-production time. Last, that PI could exhibit constant behavior for severe non-Darcy flow at early- and intermediate-production times even though transient-state condition dominates fluid flow in the porous media.
We analyzed microseismic spatial and temporal distribution, magnitudes, b-values, and treatment data to interpret and explain the observed anomalies in microseismic events recorded during exploitation of shale gas reservoirs in the Horn River Basin of Canada. The b-value shows the relationship between the number of seismic events in a certain area and their magnitudes in a semilogarithmic scale. The b-value is important because small changes in b-value represent large changes in the predicted number of seismic events. In this study, b-value is considered as an indicator of the mechanism of observed microseismicity during hydraulic-fracturing treatments.
We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. On the basis of our definition of an average front curve, we managed to separate most of the microseismic events that are related to natural-fracture activation from hydraulic-fracturing microseismic events. We analyzed b-values for microseismic events of each stage before and after separating fracture-activation microseismic events from original data, and created a map of b-values in the study area. This allowed us to approximately locate activated fractures mostly in the northeastern part of the study wellpad. The b-value map agrees with our assumption of activated-fracture locations and high ratio of seismic activities. The dominant direction of the suggested activated natural fractures agrees with the general trend of the Trout Lake fault zone located approximately 20 km west of the study area.
Suggested fracture direction also agrees with anomalous-events density, energy distribution, and treatment data. We are proposing intermediate b-values for calculation of the stimulated reservoir volume (SRV) in areas with both hydraulically fractured events and events related to natural-fracture-network activation in those instances in which it is not viable to separate events based on their origin.
This study presents an approach to determine the dimensions of three-phase separators. First, we designed different vessel configurations depending on the fluid properties of an Iranian gas/condensate field. We then devised a comprehensive computational-fluid-dynamics (CFD) method for analyzing the phenomena of three-phase separation. The results in terms of separation efficiency and behavior of secondary-phase particles were reviewed to choose the optimal configuration. Only a slight difference in the length of this vessel and the existing separator was found. In addition, simulation data were compared with industrial data pertaining to a similar existing separator. The results of this work showed that the CFD model used is capable of investigating the performance of three-phase separators.
The Fourier-series method (FSM) is used to solve the prediction problems of sucker-rod pumping systems. With the displacement and load at any point of the rod string, by means of FSM, the displacement and load at any other point of the rod string are obtained. With no need of pump models, FSM easily predicts various pumping conditions that are challenges to the conventional prediction methods. As for prediction, FSM is valuable to the design, selection, installation, and operation of sucker-rod pumping systems. As for diagnostics, the surface cards generated by FSM can be used as characteristic surface cards for diagnosis of the sucker-rod pumping systems in situations when only the surface cards are available. FSM is also a convenient method to generate surface cards for pump-diagnostic emulators in the laboratory environment.
Mayerhofer, Michael (Liberty Oilfield Services) | Oduba, Oladapo (Liberty Oilfield Services) | Agarwal, Karn (Liberty Oilfield Services) | Melcher, Howard (Liberty Oilfield Services) | Lolon, Ely (Liberty Oilfield Services) | Bartell, Jennifer (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services)
In the Williston Central Basin, a well-completion design has a significant effect on well productivity and ultimate recovery. More than 12,000 horizontal wells have been drilled and completed while completion practices continue to vary widely across the basin. Several companies have adopted slickwater-only designs, whereas others have dramatically increased proppant mass. Completion strategies have differed depending on the area in the basin. The objective of this paper is to discuss the effect of various completion changes in the Central Basin and determine which particular change delivers the most “bang for the buck” using a metric of dollars spent per barrel of oil (USD/BO).
The approach centered around multivariate analysis (MVA) from an extensive petrophysical/completion/production database to verify what completion and petrophysical parameters independently drive production in different areas. Although MVA has been used by the authors and many others before, statistical models are limited by their ability to provide predictive relationships (mostly simple linear regressions, and unreliable beyond the data range). This paper provides a novel hybrid approach that uses calibrated relationships from physics-based modeling (combination of fracture and numerical reservoir modeling) between completion parameters and production response in combination with statistical MVA results. Specifically, the physics-based model is calibrated or “history matched” to a measured production/completion-parameter response as provided by MVA, thus delivering a constrained and more physically realistic production response to suggested completion changes. This model is then coupled with a completion-cost model to determine which completion method is the most effective to lower USD/BO.
Many common completion-parameter changes, such as increasing stage intensity, moving to plug-and-perforate cemented-well designs, increasing injection rate, and increasing proppant mass per lateral foot and fluid volume per lateral foot, have a positive effect on production and are advantageous to lower USD/BO in all areas of the Middle Bakken and Three Forks. The new hybrid MVA approach indicates that pumping slickwater treatments with average proppant concentrations of 1 lbm/gal and treatment sizes from 545 to 750 lbm/ft at pump rates approaching 100 bbl/min through a stage length of 200 ft (50 stages for a 10,000-ft lateral) might be the economic optimum, provided there are no significant well-communication issues.
Laboratory-gas dynamic throughput testing indicates that each injection-operated gas lift valve (GLV) often does not open fully in actual operation, mainly because of the bellows-stacking phenomenon. This paper addresses such issues and recommends a simple but effective solution. A modified design for the GLV seat was created to reduce the required stem travel to generate a flow area equal to the port area.
This paper details the new design, theoretical calculations, and experimental results. Theoretical calculations showed that the minimum stem travel for the modified design improved from 10 to 58% compared with using a conventional sharp-edged seat. The experimental results showed that for the same amount of stem travel, the modified design provides a larger flow rate than the sharp-edged seat.
Plug-and-perforate (Plug-and-Perf) fracturing stages with multiple perforation clusters have become common practice in the industry. However, it is usually unclear whether the fluid and proppant are distributed evenly among all clusters. In this study, we present a method for computing the proppant distribution into each cluster in a fracturing stage. By integrating proppant transport into a multicluster hydraulic-fracturing model and implementing a simple screenout criterion, we show that the proppant distribution in a fracturing stage can be very uneven, with a strong bias toward the heel-side clusters even when the initial fluid distribution is uniform among all clusters.
In this work, we define the efficiency of proppant transport into a perforation by the proppant-transport efficiency (PTE), which is defined as the mass fraction of proppant transported through a perforation relative to the total mass of proppant approaching the perforation. The dynamic proppant distribution in a fracturing stage is modeled with the PTE concept in three steps. First, a series of coupled computational-fluid-dynamics/discrete-element-method (CFD/DEM) simulations were performed to obtain PTE under controlled flow conditions. Then, the CFD/DEM simulation results were statistically analyzed to generate a PTE correlation as a function of wellbore, perforation, fluid, and proppant properties. Finally, the PTE correlation was incorporated into a multicluster hydraulic-fracturing model to compute the dynamic distribution of fluid and proppant among multiple clusters in a fracturing stage.
Results from this work show that proppant concentration in the toe-side clusters can be several times higher than the injected concentration. This occurs because the high wellbore flow rate near the heel-side clusters provides proppant particles a large inertia sufficient to prevent them from turning into the perforations. Proppant concentration in the wellbore is thus increased as the slurry flows toward the toe side and the fluid preferentially leaks off from the heel-side perforations. The highly concentrated slurry increases the screenout risk of the toe-side clusters. Our modeling results show that if toe-side clusters screen out at early time in the proppant stage, fluid and proppant are redistributed to the heel-side clusters. In such a case, cumulative fluid and proppant distributions will be heel-biased. Simulation results are compared with field observations and are shown to be consistent with distributed-temperature-sensing (DTS) and distributed-acoustic-sensing (DAS) observations on proppant distribution made in three different studies.
The method presented in this work provides a way to quantify proppant transport at a wellbore scale. It shows that the uneven proppant distribution among perforation clusters is a function of fluid, perforation, and proppant properties. An estimate of proppant placement in different perforation clusters can be computed for any pumping schedule and wellbore/perforation geometry with this method. This can be used to optimize perforation clusters that will result in a more-even distribution of proppant in each cluster.
This study provides horizontal-pipe pressure-drop and liquid-holdup measurements for three-phase flow of sand, viscous oil, and gas with a focus on slug flow (SL). We developed a correlation for predicting the liquid holdup and dimensionless pressure gradient in the presence of solids during SL.
A multiphase-flow-loop facility with 1.5-in. (0.0381m) Schedule 80 polyvinyl chloride (PVC) pipes was designed and constructed to flow viscous oils ranging from 150 to 218 cp (0.15 to 0.218 Pa·s). Two-phase (221) and three-phase (88) data points were collected. A progressing cavity pump (PCP) was used to pump the complex mixture from a double-walled steel tank. Compressed air was used as the gas phase and 0 to 1 wt% of 180-µm diameter sand (test-section concentrations) was added to the flow. The facility had a clear test section for flow-pattern visualization and photography. Equipment issues and operational difficulties in the setup were identified during initial tests and rectified. Oil- and gas-flow rates, differential and absolute pressures, liquid holdup (both with and without the presence of solids), and fluid temperatures were measured, and flow-pattern observations were photographed. Gas and viscous-oil superficial velocities ranged from 0.1 to 10 m/s and from 0.1 to 1 m/s, respectively.
We validated the setup by comparing actual single-phase liquid-pressure-drop measurements to an analytical expression for computing the pressure drop during single-phase viscous-oil flow. Sand was introduced into the system thereafter. We found that the presence of sand did not shift the flow-pattern boundaries appreciably and SL was the most commonly encountered flow pattern. As such, we focused on the SL region. Slow-motion photography and videography revealed that the presence of sand disrupted the sharp head and tail profiles in the liquid-slug body. Regression analysis using the observed data revealed that for SL of viscous oil and gas, the most-important dimensionless groups affecting both the holdup and the dimensionless pressure gradient are the fluid-velocity numbers and the Froude number. For three-phase SL of sand, viscous oil, and gas, the most-important dimensionless groups for affecting holdup in the presence of solids are the fluid velocity, Reynolds number, and Froude number in addition to the pipe-diameter number and the sand fraction in the flow stream. For dimensionless pressure gradient, the most-important dimensionless groups are the fluid-velocity numbers, the Reynolds and Froude numbers, and the input-liquid fraction.
Slug-unit length was also measured, and the data were matched with an existing correlation. We also detailed the effect of sand on pattern behavior in each of the commonly observed horizontal-pipe multiphase-flow patterns using videography.
To the best of our knowledge, this is the first recorded attempt at measuring pressure drop and liquid holdup in the presence of solids for the horizontal multiphase flow of sand, viscous oil, and gas. This work provides laboratory data/models that can support the characterization of the pressure drop and flow patterns experienced in horizontal wells completed using the process of cold heavy-oil production with sand (CHOPS) and other viscous-oil-producing wells.
Hu, Yisheng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mackay, Eric (Heriot-Watt University) | Vazquez, Oscar (Heriot Watt University ) | Ishkov, Oleg (Heriot-Watt University)
In waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.
In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.