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Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
Mondal, Somnath (Shell Exploration & Production Co.) | Zhang, Min (University of Texas at Austin) | Huckabee, Paul (Shell Exploration & Production Co.) | Ugueto, Gustavo (Shell Exploration & Production Co.) | Jones, Raymond (Shell Exploration & Production Co.) | Vitthal, Sanjay (Shell Exploration & Production Co.) | Nasse, David (Shell Exploration & Production Co.) | Sharma, Mukul (University of Texas at Austin)
Abstract This paper presents advancements in step-down-test (SDT) interpretation to better design perforation clusters. The methods provided here allow us to better estimate the pressure drop in perforations and near-wellbore tortuosity in hydraulic fracturing treatments. Data is presented from field tests from fracturing stages with different completion architectures across multiple basins including Permian Delaware, Vaca Muerta, Montney, and Utica. The sensitivity of near-wellbore pressure drops and perforation size on stimulation distribution effectiveness in plug-and-perf (PnP) treatments is modeled using a coupled hydraulic fracturing simulator. This advanced analysis of SDT data enables us to improve stimulation distribution effectiveness in multi-cluster or multiple entry completions. This analysis goes much further than the methodology presented in URTeC2019-1141 and additional examples are presented to illustrate its advantages. In a typical SDT, the injection flowrate is reduced in four or five abrupt decrements or "steps", each with a duration long enough for the rate and pressure to stabilize. The pressure-rate response is used to estimate the magnitude of perforation efficiency and near-wellbore tortuosity. In this paper, two SDTs with clean fluids were conducted in each stage - one before and another after proppant slurry was injected. SDTs were conducted in cemented single-point entry (cSPE) sleeves, which present a unique opportunity to measure only near-wellbore tortuosity using bottom-hole pressure gauge at sleeve depth, negligible perforation pressure drops, and less uncertainty in interpretation. SDTs were conducted in PnP stages in multiple unconventional basins. The results from one set of PnP stages with optic fiber distributed sensing were modeled with a hydraulic fracturing simulator that combines wellbore proppant transport, perforation size growth, near-wellbore pressure drop, and hydraulic fracture propagation. Past SDT analysis assumed that the pressure drop due to near-wellbore tortuosity is proportional to the flow rate raised to an exponent, β = 0.5, which typically overestimates perforation friction from SDTs. Theoretical derivations show that β is related to the geometry and flow type in the near-wellbore region. Results show that initial β (before proppant slurry) is typically around 0.5, but the final value of β (after proppant slurry) is approximately 1, likely due to the erosion of near-wellbore tortuosity by the proppant slurry. The new methodology incorporates the increase in β due proppant slurry erosion. Hydraulic fracturing modeling, calibrated with optic fiber data, demonstrates that the stimulation distribution effectiveness must consider the interdependence of proppant segregation in the wellbore, perforation erosion, and near-wellbore tortuosity. An improved methodology is presented to quantify the magnitude of perforation and near-wellbore tortuosity related pressure drops before and after pumping of proppant slurry in typical PnP hydraulic fracture stimulations. The workflow presented here shows how the uncertainties in the magnitude of near-wellbore complexity and perforation size, along with uncertainties in hydraulic fracture propagation parameters, can be incorporated in perforation cluster design.
In the process of analyzing treatment responses that occur during hydraulic fracturing, several variances in treating pressure exist that are not readily explained by examining the surface pressures and pipe friction in isolation. These variances are also apparent when looking at bottomhole injectivity. This paper demonstrates how engineers can take advantage of their most-detailed completions and geomechanical data by identifying trends arising from past detailed treatment analyses. The Eagle Ford Shale was deposited in the Late Cretaceous Period in a marginal to open marine setting. The Lower Cretaceous part can be divided into two second-order transgressive/regressive cycles that have been labeled lower and upper Eagle Ford. The deposition of these units varies across the formation as a result of topography at the time of deposition.
The scope of this work is to introduce a technology that measures perforation effectiveness on a stage by stage basis before the hydraulic fracturing process begins. The measurement utilizes surface generated tube waves to interrogate the perforated section of the wellbore. We present three case studies demonstrating how "low perforation quality alerts" mitigate operational issues, achieving the deployment of appropriate stimulation treatments for several operators in the Eagle Ford, Haynesville, and Niobrara formations.
The reflections of tube waves are analyzed to characterize perforation effectiveness on a stage by stage basis. This methodology is non-intrusive, infinitely repeatable and can be performed in the short time interval between removing the perforating equipment from the well and beginning the fracture treatment process. The operators in our study were alerted to stages with a high likelihood of pumping issues such as high treating pressure, screen outs, or low proppant volume placement. Real-time measurements flagged these stages as having poor wellbore connectivity to the reservoir.
Prior to pumping, the operator and crew in the field were alerted to the stages that showed low perforation quality. This allowed modifications to the stage design, such as additional acid, sweeps, finer proppant, gel, increased pad, lower rate, or an additional perforation run. In the cases where changes were made to the design, the objective of mitigating pumping problems due to poor perforation performance was a success. In all the cases where preventive design changes were not implemented, downhole difficulties were experienced resulting in sub-optimal stage execution and/or screen outs. Cost savings in the range of $300,000 on some wells were achieved due to the mitigation of pumping problems associated with poor wellbore to reservoir connectivity.
Perforation quality and reservoir rock geomechanics play a dominant role in hydraulic fracturing operational success or failure. Although there have been extensive studies focusing on the role that perforation diameter plays on treatment efficiency, these studies do not adequately consider the importance of the perforation tunnel (depth and quality of perforation penetration into the near well region). Having real-time, non-intrusive, field-based data that provides a direct measurement of this essential element can influence the execution of the hydraulic fracture design. This mitigates the costly exercise of recovering from a screen out and improves the likelihood of a productive stage.
Abstract This case study helped an operator in the Powder River Basin approach an optimized completion design. The operator used geomechanical measurements, hydraulic fracture modeling, and fracture diagnostics on two horizontal wells. The two wells are near a previously-completed, producing well (i.e., “parent” well). While drilling the two horizontal wells, the operator acquired geomechanics data. This method, called drill bit geomechanics, measured the variability along the laterals. These data produced geomechanically-informed perforation and stage placements to minimize the differences in minimum horizontal stress across each stage. Additionally, the operator engineered the perforation sizes, which increased perforation friction to overcome the measured variability. The authors used the near-wellbore geomechanics data, along with other data, in a hydraulic fracture simulator. In general, standard hydraulic fracture simulators assume constant mechanical properties in each geologic layer. Compared to this standard practice, adding measured geomechanics data can more accurately predict which perforation clusters may be stimulated. To test two different fluid systems, the operator designed a “hybrid” (i.e., combination of slickwater and crosslinked gel) treatment for Well 1 and a slickwater treatment for Well 2. Fracture diagnostics reported their effectiveness. Diagnostics included: 1) proppant tracers to evaluate the perforation efficiency, 2) oil-soluble fluid tracers to quantify by-stage production contribution, and 3) water-soluble fluid tracers to assess inter-well communication. Also, the operator had used proppant tracers on the parent well, providing a baseline for results comparison. Compared to the parent well, the two study wells showed 15-22% higher perforation efficiency. This suggests the engineered design changes created more even proppant distributions. Understanding the geomechanical variability, the operator recognized the engineering required to overcome it. The oil-soluble tracer, although affected by the parent well's depletion profile, showed higher perforation efficiency can increase oil production. Between the two study wells, Well 1 had higher perforation efficiency than Well 2 and it slightly out-produced Well 2. This suggested the hybrid design was likely the more effective design. The hydraulic fracture simulator with near-wellbore geomechanics data predicted perforation efficiency similar to that measured by the proppant tracer. Across both wells’ traced stages, the predicted efficiency and measured efficiency were within 3%. The measurements validated the modeling method. This paper describes a method of improving completion designs through 1) geomechanics data measured while drilling, 2) modeled perforation cluster efficiency, 3) a measurement of proppant placement effectiveness, and 4) an estimate of stage-by-stage production. For the Powder River Basin operator, this method informed decisions about the next completion design iterations. Operators in any unconventional basin could apply this workflow to approach an optimized completion.
In horizontal-well, plug-and-perforate completions, various studies have shown that not all perforation clusters are stimulated equally. To increase perforation cluster treatment efficiency, engineers attempt to move the perforations of each stage to similarly-stressed rock. Most of these efforts have not included predictions quantifying efficiency improvements. This paper outlines a methodology for predicting improvements of perforation cluster treatment efficiency and includes a case study verifying the results of the model using pre-treatment diagnostics.
In four Western Anadarko Basin wells, the operator measured mechanical rock properties using drill bit geomechanics. These properties were used to calculate the changes in minimum horizontal stress along each ~5,000-ft horizontal well. Within each treatment stage, the engineers chose perforation locations to minimize the difference in minimum horizontal stress. Using offset vertical logs and the geosteering interpretations, the engineers built a high-resolution fracture simulation model for each well. The model included the measured mechanical properties along the wellbore path. Comparing results from a geometric perforation model and the stress-balanced perforation model, the engineers predicted increased perforation cluster efficiencies between 10 and 20%.
The four wells were completed using the stress-balanced perforation designs. Like all previous wells in the area, the operator performed step-down rate tests on these wells before each stimulation treatment. The step-down rate test is a common hydraulic fracturing diagnostic to quantify the number of open perforations taking treatment fluid. Compared to the operator's previous geometrically-perforated wells, the wells with the stress-balanced perforation designs showed more open perforations. A higher number of open perforations suggests a greater perforation cluster treatment efficiency. The increase in efficiency measured by the step-down rate tests was consistent with the model predictions.
By understanding how stress-balancing perforation clusters will affect perforation cluster treatment efficiency, operators can optimize stimulations. The industry has not widely adopted stress-balanced perforation designs or other ‘engineered’ completion strategies. The results of ‘engineered’ completion studies have often been inconclusive, likely due to small sample sizes and reliance on production results. By combining affordable measurement of rock properties, modeled perforation cluster efficiency, and an affordable measurement of perforation efficiency, this paper provides a methodology for economically optimizing multi-stage stimulations in horizontal wells.
Recently, the United States (US) oil and gas industry has dramatically increased its production, primarily due to technological advances in horizontal drilling and hydraulic fracturing. Current hydraulic fracturing practices require a significant amount of water. Section 9.2.1 of the
Many US oil and gas companies’ annual reports and public communications currently feature sustainability and environmentally-responsible development strategies. However, opportunities to minimize negative environmental impact without affecting the value of a large-scale unconventional development is extremely difficult, particularly in the current low oil price market. Operators throughout the industry are developing water management facilities focused on safe, reliable and environmentally friendly water management practices. This paper discusses utilizing in-situ mechanical rock property data to optimize completion strategies, which can help reduce the negative impacts of hydraulic fracturing, while maintaining, and often increasing, production.
Abstract The objective of this work is to assess the impact on productivity decline of altering the completion type in a deepwater Miocene reservoir. Typically to date, these types of assets have utilized Cased Hole FracPack (CHFP) completions as a basis of design. Wells in the Gulf of Mexico targeting the deepwater Miocene plays have seen significant Productivity Index (PI) decline within the first few years of production. Open Hole Gravel Pack (OHGP) and Open Hole FracPack (OHFP) completion types were selected as potential alternatives to CHFP. A coupled well, reservoir and geomechanical model was created to assess the impact of multiple potential damage components on matching the observed inflow performance from production logs. The model assesses probabilistically the weighting of each of six damage mechanisms (creep, fracture conductivity, fines migration, fracture connectivity, off-plane perforation contribution and drilling/completion fluid damage) on well performance. Based on this weighting, an assessment can then be made of their impact on the alternate completion types. Previous studies (Knobles et al. 2017) have indicated that cased hole completions are particularly susceptible to PI decline. Specifically, when unpropped perforation tunnels collapse, they reduce the inflow area into the wellbore and create a flow restriction. In higher permeability formations, the perforations not connected to the fracture (i.e. off-plane perforations) can contribute a significant portion of the well's production. It is important to note that if the connectivity and packing of the perforations is optimized and fracture is placed to within design specifications, little PI decline is observed. However, in the real world, this is not always the case. Three wells were used in this analysis. Two wells where decline was observed and a third well where no significant decline was observed. Results from the study indicated that if the two underperforming wells had utilized an OHGP completion, the PI degradation would have been mitigated. However, the upside production seen from the third well would not be attainable had the well been completed as an OHGP on an equivalent well trajectory. The results of the study also indicated that minimizing the drilling damage would be integral to the success of the OHGP completion in comparison to optimizing the completion placement in a CHFP. The paper addresses a significant issue of PI decline affecting deepwater wells and presents a potential remediation technique based on alternate completion types. The paper also presents a new methodology based on Design of Experiment to assess the contribution of various damage mechanism while incorporating the uncertainty around each based on available measurements.
Cameron, John (Chevron Energy Technology Company, a division of Chevron U.S.A. Inc.) | Zaki, Karim (Chevron Energy Technology Company, a division of Chevron U.S.A. Inc.) | Jones, Colin (Chevron Energy Technology Company, a division of Chevron U.S.A. Inc.) | Lazo, Antonio (Chevron Energy Technology Company, a division of Chevron U.S.A. Inc.)
Abstract A probabilistic flux and erosion model and workflow has been constructed to estimate the inflow through sand screen on a foot by foot basis along the wellbore using the completion details, production rate, and reservoir and bottom hole flowing pressures. The model is then calibrated & history matched using well data from pressure transient analyses, well test and production logs as available. Extensive laboratory testing coupled with computational flow dynamics modelling provided the algorithms for a number of different screen types to relate flux and sand production to the expected service life for any given future production profile. This allows the well's planned production profile to be optimized by balancing risk, rate and reserves recovery.
Pathak, Shashank (Cairn Oil & Gas, Vedanta Ltd.) | Tibbles, Raymond Joseph (Cairn Oil & Gas, Vedanta Ltd.) | Tiwari, Shobhit (Cairn Oil & Gas, Vedanta Ltd.) | Anand, Saurabh (Cairn Oil & Gas, Vedanta Ltd.) | Ranjan, Vishal (Cairn Oil & Gas, Vedanta Ltd.) | Siddarth, Punj (Cairn Oil & Gas, Vedanta Ltd.) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd.)
Abstract This paper documents the basis of fracturing diagnostic test design and analysis methodology adopted while fracturing one of the few commercial volcanic gas reservoir in the world. More than 10 distinct types of diagnostic tests were performed with each having specific objective. These tests were primarily conducted to: Reduce the uncertainty while fracturing Improve reservoir & hydraulic fracture understanding to enhance production Validate qualitative sources of information These tests included standard pre-frac injection tests, post injection surveys as well as innovative modifications which significantly helped to enhance operational efficiency and improved production results. To achieve maximum net pay coverage with minimum number of frac stages, limited entry fracture technology best suited the economics of this field. Since limited entry technique was selected even with its inherent uncertainties with respect to diversion in individual fracture cluster, the overall performance of this field heavily depended on its effectiveness. To maximize the probability of success, uncertainties & risks were evaluated and a workflow was designed. This workflow consisted diagnostic tests with specific deliverables such as DFITs to calibrate mechanical earth model (MEM), Step rate tests to estimate the efficiency of fluid diversion, temperature surveys to validate fluid distribution, production logs to confirm production performance. These standard tests were also modified to minimize cost/time implication while ensuring specific information was acquired as expected from these tests. Fracture model calibration was achieved by a combination of injection tests, post injection test/fracturing temperature surveys, along with a consistent method for fracture history matching. Final verification was obtained using a series of production logs. Over 13 Diagnostic Fracture Injection Tests (DFITS), 63 Step Rate Tests (SRT), 80 Step Down Tests, 58 post SRT/Fracturing Temperature Surveys, over 50 production logs are incorporated in this study. All of this augmented reservoir understanding and helped to save operational time and reduce cost. These tests further helped to increase from 3 clusters per frac to 6 cluster per frac, thus increased net pay coverage with same frac stages. The contribution of 6 clusters was also validated from production logs. Completion improvements have resulted in productivity and Estimated Ultimate Recovery (EUR) increases of 80% and 20% respectively. Screen out rates have dropped from 33% in the very first campaign to 5% in the most recent campaign. Detailed analysis and key engineering findings from all of these tests. Representative case histories including, DFITS, Step rate tests, Mini Fracs, Temperature surveys and production logs to back up the results. The results from these learnings are summarized in this paper.