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Abstract Evaluating Electrical Submersible Pumps (ESPs) [SS1] [NA2] run-lives and performance in unconventional well environments is challenging due to many different factors -including the reservoir, well design, and production fluids. Moreover, reviewing the run-lives of ESPs in a field can be rather complex since the run-life data is incomplete. Often ESPs are pulled while they are still operational, or the ESP has not been allowed to run until failure. These are some of the complications that arise when gauging ESP performance. A large dataset of ESP installs was assessed using Kaplan-Meier survival analysis for the North American unconventional application to better understand those factors that may affect ESP run lives. The factors were studied including but are not limited to the following: Basin and producing formation Comparing different ESP component types such pumps and motors, and new or used ESP components Completion intensity of the frac job (lb/ft of proppant) Kaplan-Meier survival analysis is one of the commonly used methods to measure the fraction or probability of group survival after certain time periods because it accounts for incomplete observations. Using Kaplan-Meier analysis generates a survival curve to show a declining fraction of surviving ESPs over time. Survival curves can be compared by segmenting the runlife data into buckets (based on different factors), therefore to analyze the statistical significance of each and how they affect ESP survivability. Kaplan-Meier analysis was performed on the aforementioned dataset to answer these questions in order to better understand the factors that affect ESP runlives in North American unconventional plays. This work uses a unique dataset that encompasses several different ESP designs, with the ESPs installed in different North American plays. The observations and conclusions drawn from it, by applying survival analysis, can help in benchmarking ESP runtimes and identifying what works in terms of prolonging ESP runlife. The workflow is also applicable to any asset in order to better understand the drivers behind ESP runlife performance.
Abstract There are mainly two types of solids in the oil field waters; Suspended Solids (SS) and Total Dissolved Solids (TDS). While it is easy to remove SS from water, removal of TDS requires the application of advance filtration techniques such as reverse osmosis or ultra-filtration. Because these techniques cannot handle high volumes of the oilfield waters with high TDS content, produced waters originated from hydraulic fracturing activities cannot be treated by using these advance technologies. Thus, in this study we concentrated on the pretreatment of these waters. We investigated the feasibility of the Coagulation, Flocculation, and Sedimentation (CFS) process as pretreatment method to reduce mainly SS in Produced Water (PW) samples. We collected samples from 14 different wells in the Permian Basin. First, we characterized the water samples in terms of pH, SS, TDS, Zeta potential (ZP), Turbidity, Organic matter presence and different Ion concentration. We tested varying doses of several organic and inorganic chemicals, and on treated water samples we measured pH, TDS, SS, Turbidity, ZP and Ions. Then, we compared obtained results with the initial PW characterizations to determine the best performing chemicals and their optimal dosage (OD) to remove contaminants effectively. The cation and anion analyses on the initial water samples showed that TDS is mainly caused by the dissolved sodium and chlorine ions. ZP results indicated that SS are mainly negatively charged particles with absolute values around 20 mV on average. Among the tested coagulants, the best SS reduction was achieved through the addition of ferric sulfate, which helped to reduce the SS around 86%. To further lessen SS, we tested several organic flocculants in which the reduction was improved slightly more. We concluded while high TDS in the Permian basin does not implement a substantial risk for the reduction of fracture conductivity, SS is posing a high risk. Our study showed, depending on components of the initial PW, reuse of the pretreated water for fracturing may minimize fracture conductivity damage.
Abstract This paper presents a simple method to model boundary-dominated flow in hydraulically fractured wells, including horizontal wells with multiple fractures. While these wells are almost always producedat more nearly constant BHP rather than constant rate, use of material-balance time transforms variable-rate production profiles to constant-rate profiles, allowing us to use the pseudo-steady-state (PSS) flow equation for modeling. However, the PSS equation requires use of shape factors in applications, and shape factors available in the literature are available only for square-shaped bounded reservoirs with hydraulic fractures. In this work, we derived shape factors for wells centered in rectangular-shaped drainage areas with different length-to-width aspect ratios. The superposition principle can be used to transform transient radial flow and transient linear flow solutions into bounded reservoir solutions. At large times (when boundary-dominated flow is established), results from these solutions are similar to those obtained from the PSS equation. Therefore, for a pre-defined reservoir geometry, pressure drop values from superimposed transient flow equationscan be substituted back into the PSS equation to calculate shape factors for that reservoir geometry.We used shape factors previously presented by other authors for square drainage areas to validate themethod before applying it to calculate shape factors for more general drainage area configurations. We present shape factors for different fracture half-length to fracture-spacing ratios ranging from 0.2 to 10. Calculated shape factors, when plotted against the fracture half-length to fracture-spacing ratio, produced a smooth curve which can be used to interpolate shape factor values for other fracture configurations. We present applications of this methodology to example low-permeability wells. The use of the PSS equation for wells with vertical fracturescan be extended to multi-fractured horizontal wells (MFHWs) by incorporating the number of fractures in the equation; hence, shape factorsderived for wells with vertical fractures can also be used for MFHWs. Although our results are rigorously correct only for fluids with constant compressibility, use of pseudo-pressure and pseudo-time transformations extend application to compressible fluids, notably gases. Using the PSS equation in production data analysis allows us to calculate contributing reservoir volume and drainage area in a simple manner not requiring use of specialized software.
Donald A., Anschutz (PropTester, Inc.) | Patrick J., Wildt (PropTester, Inc.) | K. Michelle, Stribling (PropTester, Inc.) | Jim, Craig (Sintex Minerals & Services) | Luiz R., Curimbaba (Mineracao Curimbaba LTDA) | Pedro, Silva (Sintex Minerals & Services) | Ibrahim S., Abou-sayed (i-Stimulation Solutions Inc.)
Abstract While the shale revolution flourished prior to the pandemic, the increased supply bubble had already taken a toll on the profitability of horizontal wells with multiple transverse fractures. A significant shift previously occurred to reduce proppant costs by utilizing cheaper, smaller grained, lower strength, and broadly diverse grain sized sands. Due to the extremely low matrix permeability in active unconventional plays, the use of regional 40/70 and 100 mesh sands (50/140, 70/140, etc.) has become commonplace with adequate results. What remains is the need for enhanced conductivity near the wellbore to handle the radial flow convergence loss when the well is brought on-line. Research is being conducted to better understand how to efficiently increase near-wellbore conductivity using lead and tail-in stages with higher permeability (ceramic) proppant when frac sand is the majority of the material pumped into the well. A 10’x20’ Large Slot Flow (LSF) apparatus, equipped with multiple injection points, side-panel ports for leak-off and/or post-test injection, with the ability to be disassembled for sample analysis after testing, was utilized for this project. For this data, the inlet was moved to the centerline of the wall to allow for proppant and fluid to transport into an environment similar to a horizontal wellbore connecting with a transverse fracture. Various tests were conducted to study the depositional characteristics of lead and tail-in stages with ceramic proppant (15% BW-Lead, 5% BW-Tail) and a main stage of 100 mesh sand (80%). Three inlet positions were established in the lower, middle, and upper portion of the apparatus. Tests were recorded to visually capture the efficiency of placing the premium proppants near the wellbore for increased conductivity. A key addition to the study was the innovative, post-production analysis through the side-panel ports. Fluid was injected into the proppant pack to observe the effect of increased near-wellbore conductivity. To improve visibility, the fluid was colored with a fluorescent dye and observed under black lights. The injection front geometry was radial initially, but typically elongated toward the exit point after contacting the ceramic proppant. The amount of time and distance for the fluid to travel through the sand pack, as well as that for the fluid to reach the offtake point once the ceramic bed was reached, were monitored and recorded. The ratio of the velocities should represent a valid qualitative indication of the conductivity contrast of the two proppants. This paper will describe the unique experimental configuration, outline the testing program for both deposition and post-production assessments performed on the deposits, along with results that could provide better design practices leading to improved transverse fracture performance.
Witt-Doerring, Ysabel (The University of Texas at Austin) | Pastusek, Paul Pastusek (ExxonMobil UIS) | Ashok, Pradeepkumar (The University of Texas at Austin) | Oort, Eric van (The University of Texas at Austin)
Abstract It is useful during drilling operations to know when bit failure has occurred because this knowledge can be used to improve drilling performance and provides guidance on when to pull out of hole. This paper presents a simple polycrystalline diamond compact (PDC) bit wear indicator and an associated methodology to help quantify wear and failure using real-time surface sensor data and PDC dull images. The wear indicator is used to identify the point of failure, after which corresponding surface data and dull images can be used to infer the cause of failure. It links rotary speed (RPM) with rate of penetration (ROP) and weight-on-bit (WOB). The term incorporating RPM and ROP represents a "sliding distance", i.e. the number of revolutions required to drill a unit distance of formation, while the WOB represents the formation hardness or contact pressure applied by the formation. This PDC bit wear metric was applied and validated on a data set comprised of 51 lateral production hole bit runs on 9 wells. Surface electric drilling recorder (EDR) data alongside bit dull photos were used to interpret the relationship between the wear metric and observed PDC wear. All runs were in the same extremely hard (estimated 35 – 50 kpsi unconfined compressive strength) and abrasive shale formation. Sliding drilling time and off-bottom time were filtered from the data, and the median wear metric value for each stand was calculated versus measured hole depth while in rotary mode. The initial point in time when the bit fails was found to be most often a singular event, after which ROP never recovered. Once damaged, subsequent catastrophic bit failure generally occurred within drilling 1-2 stands. The rapid bit failure observed was attributed to the increased thermal loads seen at the wear flat of the PDC cutter, which accelerate diamond degradation. The wear metric more accurately identifies the point in time (stand being drilled) of failure than the ROP value by itself. Review of post-run PDC photos show that the final recorded wear metric value can be related to the observed severity of the PDC damage. This information was used to determine a pull criterion to reduce pulling bits that are damaged beyond repair (DBR) and reduce time spent beyond the effective end of life. Pulling bits before DBR status is reached and replacing them increases overall drilling performance. The presented wear metric is simple and cost-effective to implement, which is important to lower-cost land wells, and requires only real-time surface sensor data. It enables a targeted approach to analyzing PDC bit wear, optimizing drilling performance and establishing effective bit pull criteria.
Ramiro-Ramirez, Sebastian (The University of Texas at Austin) | Flemings, Peter B. (The University of Texas at Austin) | Bhandari, Athma R. (The University of Texas at Austin) | Jimba, Oluwafemi Solomon (Equinor US)
Abstract We measured steady-state liquid (dodecane) permeability in four horizontal core plugs from the middle member of the Bakken Formation at multiple effective stress conditions to investigate how permeability evolves with confining stress and to infer the matrix permeability. Three of the four tested samples behaved almost perfectly elastically as the hysteresis effect was negligible. In contrast, the fourth sample showed a permeability decrease of ~40% at the end of the test program. Our interpretation is that the closure of open artificial micro-fractures initially present in the sample (based on micro-CT imaging) caused that permeability hysteresis. The matrix permeability to dodecane (oil) of the tested samples is between ~50 nD and ~520 nD at the confining pressure of 9500 psi. The 520 nD sample exhibited the lowest porosity, the highest calcite content, and the largest dominant pore throat radii. In contrast, the 50 nD sample was more porous, and exhibited the highest dolomite content and the smallest dominant pore throat radii. This study shows that our multi-stress testing protocol allows the study of the permeability hysteresis effect to interpret the matrix permeability. We also document the presence of middle Bakken lithologies with permeabilities up to one order of magnitude greater than others. These permeable lithologies may have a significant contribution to well production rates.
This paper reviews the properties of iron compounds (such as iron oxides, iron hydroxides, and iron sulfides) and their impact in shale produced water treatment with an emphasis on the colloidal form of these compounds (small particle size, high surface charge). A wide range of problems is associated with these compounds in produced water including emulsion stabilization, oil-coated solids, pad formation in separators, pipeline solids, and plugging of water disposal formations. In conventional oil and gas production, the role that iron plays and the mitigation strategies for these problems are reasonably well known. In the burgeoning shale industry, the situation is quite different. Not only are iron concentrations significantly higher than in conventional produced water, but the colloidal properties of iron compounds are only recognized by a handful of specialists. In addition, other colloidal particles such as clays and silts are also present at high concentrations in the produced water. Produced water treatment to remove solids in Permian shale produced water is rather hit or miss. We were brought to this realization a couple years ago when testing formation plugging in Permian disposal wells.
Expanding its holdings further in the Delaware Basin, WaterBridge Holdings closed a transaction with Colgate Energy to acquire the produced water infrastructure associated with Colgate's purchase of Occidental acreage in June. The companies entered into a 15-year produced water management agreement for all of Colgate's operated acreage within Reeves and Ward counties, Texas. The acquired assets include 10 water-handling facilities and associated water midstream infrastructure with aggregate handling capacity of approximately 100,000 B/D and approximately 50 miles of produced water pipelines. WaterBridge will manage the produced water infrastructure and integrate these assets into its broader southern Delaware operations. WaterBridge and Colgate have consolidated existing produced water management contracts into a new produced water management services agreement in which Colgate has dedicated all the operated acreage recently acquired from Occidental and the legacy Colgate and Luxe Energy acreage previously dedicated to WaterBridge.
Summary North American shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for the maximum rate of penetration (ROP). Downhole mud motor power sections have rapidly advanced to deliver more horsepower and torque, resulting in different downhole dynamics that have not been identified in the past. High-frequency (HF) compact drilling dynamics recorders embedded in the drill bit, mud motor bit box, and motor top subassembly (top-sub) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. Three-axis shock, gyro, and temperature sensors placed above and below the power section measure the dynamic response of power transfer to the bit and associated losses caused by back-drive dynamics. Detection of back-drive from surface measurements is not possible, and many measurement-while-drilling (MWD) systems do not have the measurement capability to identify the problem. Motor back-drive dynamics severity is dependent on many factors, including formation type, bit type, power section, weight on bit, and drillpipe size. The torsional energy stored and released in the drillstring can be high because of the interaction between surface rotation speed/torque output and mud motor downhole rotation speed/torque. Torsional drillstring energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration, rapid fatigue on downhole equipment, and motor or drillstring backoffs and twistoffs. A new mechanism of motor back-drive dynamics caused by the use of an MWD pulser above a steerable motor has been discovered. HF continuous gyro sensors and pressure sensors were deployed to capture the mechanism in which a positive mud pulser reduces as much as one-third of the mud flow in the motor and bit rotation speed, creating a propensity for a bit to come to a complete stop in certain conditions and for the motor to rotate the drillstring backward. We have observed the backward rotation of a polycrystalline diamond compact (PDC) drill bit during severe stick-slip and back-drive events (−50 rev/min above the motor), confirming that the bit rotated backward for 9 milliseconds (ms) every 133.3 ms (at 7.5 Hz), using a 1,000-Hz continuous sampling/recording in-bit gyro. In one field test, multiple drillstring dynamics recorders were used to measure the motor back-drive severity along the drillstring. It was discovered that the back-drive dynamics are worse at the drillstring, approximately 1,110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring backoffs and twistoffs in a particular field. A motor back-drive mitigation tool was used in the field to compare the runs with and without the mitigation tool while keeping the surface drilling parameters nearly the same. The downhole drilling dynamics sensors were used to confirm that the mitigation tool significantly reduced stick-slip and eliminated the motor back-drive dynamics in the same depth interval. Detailed analysis of the HF embedded downhole sensor data provides an in-depth understanding of mud motor back-drive dynamics. The cause, severity, reduction in drilling performance and risk of incident can be identified, allowing performance and cost gains to be realized. This paper will detail the advantages to understanding and reducing motor back-drive dynamics, a topic that has not commonly been discussed in the past.
Summary The pressure decline data after the end of a hydraulic fracture stage are sometimes monitored for an extended period of time. However, to the best of our knowledge, these data are not analyzed and are often ignored or underappreciated because of a lack of suitable models for the closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that are available in unconventional horizontal wells with multistage, transverse hydraulic fracturing. The methods presented in this study allow us to quantify closure stress and average pore pressure inside the stimulated reservoir volume (SRV) and to infer the uniformity of proppant distribution without additional data acquisition costs. For the first time, field data of diagnostic fracture injection test (DFIT), flowback, and pressure decline of main fracturing stages from the same well are compared and analyzed. We found that the early-time main fracturing stage pressure decline trend is controlled by fracture tip extension, followed by progressive hydraulic fracture closure on the proppant pack, whereas late-time pressure decline reflects linear flow. When DFIT data are not available, pressure decline analysis of a main hydraulic fracturing stage can be a substitution if it can be monitored for an extended period to allow fracture closure on proppants and asperities.