Dissolvable fracturing plugs are used for hydraulic fracturing applications. However, most new dissolvable materials have slow or no degradation in low-temperature formations. A new low-temperature dissolvable fracturing plug was developed for low-temperature formations. This new dissolvable fracturing plug is composed of a high-strength metal with elastomeric seals that dissolves completely in lower-temperature wellbore fluids.
Traditional fracturing plugs are constructed from composite materials and nondissolving elastomers. These nondissolving fracturing plugs obstruct production and need to be milled out after fracturing is completed. Dissolvable fracturing plugs dissolve in wellbore fluid, eliminating the need for a separate mill run intervention into the wellbore. However, the dissolution process slows in lower-temperature shale formations and the elastomer often ceases degradation at these lower temperatures. Therefore, a new metal and elastomer was developed that allows for the complete dissolution of the fracturing plug in lower-temperature formations.
The new low-temperature fracturing plug is optimized for use with the fluids used and temperatures experienced in the Marcellus and Permian basins. Comprehensive laboratory testing was conducted on the dissolvable metal alloy and dissolvable elastomer for the new low-temperature dissolvable fracturing plug. The dissolvable metal alloy is a metallic alloy that is combined with a dopant. Metallographic analysis illustrates the effect of the dopant on the dissolution of the metallic alloy and the accelerated dissolution needed for lower-temperature formations. The dissolvable elastomer uses a hydrolytic degradation reaction that is accelerated for low-temperature fluids. The result is a high-strength fracturing plug that can be set anywhere within the wellbore and will dissolve completely at formation temperatures between 120 and 180°F. The high-strength dissolvable materials allow dissolution in water-based wellbore fluid, formation fluid, or production fluid.
The novel fracturing plug is designed for low-temperature plug-and-perf applications and is composed of a new high-strength engineered metal and elastomer. Complete dissolution of the fracturing plug eliminates the need for a separate mill run intervention into the wellbore, which helps reduce costs, operation time, and risks to personnel. This paper discusses the development of the dissolvable metal, the development of the dissolvable elastomer, and the tested behavior of the low-temperature dissolvable fracturing plug.
A method that integrates data from many sources, improving the understanding of reservoir variability and structural challenges, can enable optimal shale well completions for increased production vs. geometric completions, Schlumberger Senior Petrophysicist Kevin Fisher told the SPE Gulf Coast Section Reservoir Study Group recently. It is a subject he has also been addressing as an SPE Distinguished Lecturer for 2016–2017.
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).
Pump rates and intra stage shut-ins.
Fluid types and viscosity-alteration (friction reducer and crosslinker).
Proppant slurry and clean fluid sweep stages.
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.
A new degradable elastomeric element has been developed for frac plugs that enable a fully dissolvable frac plug to be used in "plug-and-perf" style hydraulic fracturing applications. The dissolvable frac plug operates similarly to a traditional frac plug and can be set anywhere in the wellbore to isolate individual zones. The performance of the degradable element has been demonstrated in laboratory testing and in field runs.
Traditional frac plugs are constructed with a traditional elastomeric rubber as the sealing element. After hydraulic fracturing is complete, traditional frac plugs restrict production flow and must be removed. Consequently, a separate intervention is required to mill out the traditional plugs after fracturing. Dissolvable metal has been developed to enable the dissolution of the rigid structural components of the frac plug. A hydrolytically degradable elastomer enables the complete elimination of all of the components of the frac plug. As a result, the novel dissolvable frac plug eliminates the need for a separate mill run intervention into the wellbore and leaves an unrestricted wellbore for production. The high-strength dissolvable elastomer enables dissolution of the seal in water-based wellbore fluid, formation fluid, or production fluid.
Comprehensive laboratory testing and field jobs have been performed with the new degradable elastomer for the dissolvable frac plug. The degradable elastomer is a polymeric material that can be compression set like a traditional element to form a seal between the mandrel and the casing. The elastomer is a hydrolytically degradable polymer, and the dissolution occurs as the wellbore fluid interacts with the crosslink bonds in the polymer. Dissolution is further enhanced by the elevated downhole formation temperature. The high-strength dissolvable elastomer enables the creation of a seal anywhere in a wellbore. The result is a new dissolvable frac plug that operates like a traditional frac plug and can be set at any position within the wellbore. Dissolvable frac plugs with degradable elastomeric seals have been used successfully in multiple shale zones in multiple countries.
The novel frac plug is designed for plug-and-perf applications and provides sealing with a new high-strength engineered elastomer that will degrade in wellbore fluid. The complete dissolution of the frac plug eliminates the need for a separate mill run intervention into the wellbore, reducing operational costs, time and risk. This paper discusses the development of the dissolvable elastomer, performance testing of the elastomer as a frac element, dissolution behavior of the elastomer, and the use of the frac plug in field applications.
As is well known, hydraulically fractured horizontal wells have been extremely successful in the development of low permeability reservoirs throughout the world. The vast majority of these completions employ cased and cemented wellbores drilled approximately in the direction of minimum horizontal stress. Multiple, relatively short perforation clusters are included within each frac stage along the lateral. This efficiently creates many hydraulic fractures propagating orthogonal to the well, but it does not insure that each perf cluster is effectively stimulated.
Many efforts have been made to improve the effectiveness of horizontal completions. This has mainly focused on using lateral measurements to place perforation clusters in rock of similar stress so they are more likely to be successfully stimulated. But this ignores the impact of formation initiation pressure and tectonics on fracture initiation. In addition, the number, dimensions and orientation of the perforations in each cluster can greatly influence the effectiveness of the stimulation at each initiation point.
To address these issues a near-wellbore fracture initiation calculator has been developed that predicts whether a fracture will initiate at a perforation, the minimum initiation pressure, the fracture initiation location and orientation at each perforation, and the injection rate into each perforation. These parameters are a function of the casing size and orientation, the mechanical properties of the rock and cement, the principle effective stresses, and properties of the perforations.
A series of sensitivities have been performed to quantify the impact of injection rate, tectonic setting, stress variation between clusters, and perforation properties on hydraulic fracture creation, orientation and complexity at each perf cluster. The sensitivities demonstrate that fractures may not initiate at many clusters and that within an active cluster some perforations may not be accepting fluid. Incorporating the results from this model enables engineers to design completions that insure all perforation clusters are effectively stimulated and near-well fracture complexity is minimized.
This methodology does not just look at a single perforation, or cluster. Instead, it accounts for the stress variation between multiple perforation clusters within a frac stage, in addition to perforation orientation, dimensions and eccentricity, to predict the likelihood that each perforation cluster will be stimulated. By employing this methodology one can better design a perforating system and optimize perforation placement within a lateral to insure hydraulic fractures are created at all perforation clusters.
Anifowoshe, Olatunbosun (Schlumberger) | Yates, Malcolm (Schlumberger) | Xu, Lili (Schlumberger) | Dickenson, Paul (Schlumberger) | Akin, Josiah (Schlumberger) | Carney, B. J. (Northeast Natural Energy LLC) | Hewitt, Jay (Northeast Natural Energy LLC) | Costello, Ian (Northeast Natural Energy LLC) | Arnold, Zach (Northeast Natural Energy LLC)
The variability of reservoir properties across the lateral section of horizontal shale wells remains a prevalent phenomenon that has been observed in the development of numerous unconventional plays. However, the majority of wells in these plays are completed geometrically without account for the heterogeneity present across the wellbore thereby resulting in non-uniform production profiles along the length of the wellbore. This assertion is further validated by production logs from over 250+ horizontal shale wells which show that only about 60% of perforation clusters contribute to production in these wells, meaning 40% of the wellbore are not effectively stimulated. In recent years, operators have improved upon the geometric completion technique using an engineered approach which has resulted in better completion efficiency and production performance.
This paper presents a case study of a horizontal well drilled in the Marcellus shale and equipped with a permanent fiber optic cable to investigate the effectiveness of the engineered completion approach compared to the standard geometric method. For this evaluation, the lateral length of the horizontal study well was divided into different sections. One section of the lateral employed geometric perforation placement while the perforations on another section were designed using an engineered approach. To address the challenges of perforation placement introduced by the fiber-optic cable, an enhanced perforation design methodology was implemented which leveraged the available geomechanical properties along with the wellbore and fiber-optic configurations, perforation gun specifications, and stimulation treatment design parameters to predict perforation breakdown pressures along the wellbore. Using the predicted breakdown pressures, the limited entry technique was then applied to engineer the perforation strategy for each of the stages to improve the likelihood of initiation from all of the perforation clusters. The distributed temperature and acoustic measurements from the fiber optic cable were then analyzed during the fracturing treatment to provide insight into which of the perforation clusters were initiating hydraulic fractures and being effectively stimulated.
Observations from the fiber optic data consistently showed that all perforation clusters were immediately initiated for the engineered stages with uniform acoustic energy distributions occurring across all clusters which further indicated uniform stimulation across all of perforation clusters. For the geometric stages, only about 40% to 60% of the perforation clusters became activated with intermittent acoustic energy distributions being observed across all clusters throughout the treatment stages.
The case study discussed in the paper presents and validates a novel approach for improving the wellbore stimulation coverage in an unconventional development. Through the characterization and incorporation of reservoir heterogeneity into the engineered completion design workflow, completion efficiency can be improved leading to enhanced well performance and project economics.
The Lower Triassic Montney Formation produces from the Western Canadian Sedimentary Basin. This shale play is extensive as it covers nearly 57,000 square miles. The play consists of landing intervals in the Lower, Middle, and Upper Montney Formation for which the oil and gas industry uses multiple fractured horizontal well completions to recover natural gas. Both cased and open hole completions are utilized in the Montney Formation. Identifying the key drivers for success of multiple fractured horizontal wells is not straightforward, especially in unconventional reservoirs like the Montney.
One study by
This work documents the statistical analysis of 296 cased-hole horizontal gas well completions in the Upper and Lower Montney. The work extends the previous statistical study of Montney completions by focusing on cased hole completions, including completion cluster information, and examining the performance of Upper and Lower Montney completions separately.
Results of this analysis show that cumulative gas production per cluster decreases as more perforation clusters are placed in both the Upper and Lower Montney. The study demonstrates that the cumulative gas production per cluster and initial gas production (IP) is higher for the Upper Montney Formation than the Lower Montney Formation.
This work benefits the industry by:
Providing a more focused statistical analysis of horizontal gas well cased hole completion performance in the Montney, compared to recent literature documenting industry practices. Identifying a maximum recommended liquid per cluster amount for completions in the Montney Formation. Providing a comparison of Upper and Lower Montney cased hole completion performance.
Providing a more focused statistical analysis of horizontal gas well cased hole completion performance in the Montney, compared to recent literature documenting industry practices.
Identifying a maximum recommended liquid per cluster amount for completions in the Montney Formation.
Providing a comparison of Upper and Lower Montney cased hole completion performance.
Drilling horizontal wells and multi-stage hydraulic fracturing have become essential for economically producing oil and gas from unconventional resource plays. Selection of appropriate intervals for perforation clusters (in cased holes) is key for a successful fracturing job in horizontal wells. An inappropriate interval may lead to high breakdown pressures or even inability to breakdown which can prevent that part of the well from contributing to the production. There are two approaches commonly used in selection of perforation cluster intervals, geometric approach and engineered approach. In most cases where geometric staging was adopted, only 30% of the stages contributed to 70% of production. Engineered staging where perforation intervals are selected based on minimum horizontal stress along the lateral has proven to be more effective and increased production contribution of each stage. However, we found this approach can be effective only in normal stress regime. In other stress regimes, e.g. strike-slip and reverse stress regimes, breakdown pressures were found to be higher in intervals of lower horizontal stress contrary to what we typically see in normal stress regime.
We observed that breakdown pressure depends on the differential stress acting on borehole rather than one single stress, higher the difference between the two stresses (Δσ) acting on the borehole lower the breakdown pressure is. We also observed that well azimuth moving away from the minimum stress azimuth lowers the breakdown pressure in normal stress regime, however, in non-normal stress regimes, this effect is opposite. Therefore, for regions where non-normal stress regimes are dominant, conventional engineered approach in which stages are selected based on minimum horizontal stress cannot be applied. We present in this paper a new and more effective approach where a balance between the lowest minimum stress and minimum breakdown pressure is taken into account to design completions that favor both initiation and fracture extension in complex stress regimes. We demonstrate case studies from Saudi Arabia's unconventional plays where this approach has been applied successfully.
Theory and Methodology
Mechanical behavior of rock depends on its inherent physical properties (stiffness, Poisson's ratio, strength, etc.) and the in-situ stress field to which it is subjected to. In-situ stresses are principal stresses acting in three orthogonal directions, vertical and two horizontal stresses (σv, σHmax, and σhmin) referred to as the largest, intermediate and smallest principal stresses. To fully describe the state of stress at a point in the subsurface, it is necessary to determine the magnitudes and orientations of these three principal stresses.
Production rates in unconventional plays can decline dramatically, up to 70% in the first year. Refracturing—by today's understanding—is a remedial production operation often done because original fracturing failed to contribute any significant amount of flow, performance of the initial completion has degraded over time to below operationally or economically acceptable limits, or significant unfractured pay exists in the well.
Developments in nondamaging, degradable diverters with outstanding plugging efficiency have opened new opportunities for protecting existing fractures by plugging them and then fracturing zones that were previously bypassed because of inefficient zone coverage or refracturing zones that were inefficiently fractured initially. In fact, these new diverters enable zonal isolation for horizontal wells with multiple perforation clusters and for temporarily plugging perforations for re-stimulation treatments instead of squeezing the perforations and sealing them off. With multistage operations becoming the industry norm, operators need easily deployable diversion technologies that will protect previously stimulated perforations and enable adding new ones to untreated perforations or bypassed zones.
This paper reviews in-stage Diversion, including a brief discussion of diverter candidate selection in terms of production and risk assessment to ensure return on investment. Also included is an explanation of underlying mechanisms controlling the diversion process and the use of advanced modeling techniques to enhance efficiency of diversion operations. Then a case study is discussed to highlight how temporary and degradable chemistry can be used to enhance zone coverage, to provide temporary isolation between zones in shale fracturing operations, and to achieve multiple effective fracture treatments within the same stage. These degradable chemical diverting agents form a solid impermeable barrier or seal that in time will break or degrade to liquid form, leaving the existing zone that was diverted open to permit flow.
Rondon, Janz (Schlumberger) | Heaton, Natalia (Schlumberger) | Lutken, Gordon (Schlumberger) | Parker, Jeff (Marathon Oil) | Kothare, Sunny (Marathon Oil) | Porter, Hank (Marathon Oil) | Lowe, Stephanie (Schlumberger)
A new sequenced fracturing technique is presented that allows for further increases in reservoir contact in the developed multi-stage completion scheme utilized in the Williston Basin – cemented liner, plug and perforation. The performance of this composite diverter (or pill), with respect to stimulating more clusters and the resulting production, is evaluated using a detailed workflow in which real-time pressure observations are made, data is collected and analyzed using fracturing simulation tools, and production is compared with that of offset wells stimulated with conventional propped fracturing designs.
The success of the diversion will be presented as results from such analytic methods as observation of surface pressure responses to the pill’s placement into the formation, rate step-down tests for analysis of near-wellbore effects, and statistical evaluation of production data. The step-down tests provide comparisons of how many perforation clusters are stimulated before and after the pill, which will illustrate both the performance of plugging and diversion and the comparison to fracture counts in conventionally stimulated wells. Production comparisons between the test wells and offsets give an indication of increased reservoir contact resulting from diversion, and results from tracer collection illustrate which intervals (between diverter-treated and conventional) are contributing to production.
Over the 102 intervals in which the sequenced fracturing technique was implemented on the four cemented, plug-and-perf wells, significant diversion was observed in 97 of those, a 95% success rate. The success criteria for this condition were based on observation of increases in surface treating pressure at the constant-rate pill placement into the formation. Changes in instantaneous shut-in pressures (ISIP) before versus after the pill and overlays of treating pressure before and after the pill were also analyzed as metrics of diversion success, and it was found that 81% of test intervals met the success criteria for ?ISIP. Step-down tests indicated a reduction in perforations taking fluid from before the pill to after its placement, which supports the theory that this technique was effective in plugging fractures initially taking fluid.
The success of fracture plugging and diversion was reinforced by analysis of the near wellbore effects obtained from the step-down tests, which illustrated that the tortuosity reduction achieved by acid following the pill was significantly greater than the reduction observed during the placement of the first acid spear (following the ball) – indicating that new perforation clusters were being treated after the pill. Production data supported the theory that diversion and increased reservoir contact was achieved, due to the performance of test wells versus offset wells treated with similar, but conventional, hydraulic fracturing designs. The wells within the study on which diverter was pumped across the entire lateral produced, on average, in the 71st percentile among each of their groups of offset wells after 150 producing days. Three of these were P90, P81, and P80 wells, but the fourth cemented well, producing in the 31st percentile, due to increase in water cut after artificial lift pump installation.