Quintero, Harvey (ChemTerra Innovation) | Farion, Grant (Trican Well Service LTD.) | Gardener, David (ChemTerra Innovation) | O'Neil, Bill (ChemTerra Innovation) | Hawkes, Robert (Trican Well Service LTD.) | Wang, Chuan (ChemTerra Innovation) | Cisternas, Pablo (American Air Liquide) | Pruvot, Antoine (American Air Liquide) | McAndrew, James (American Air Liquide) | Tsuber, Leo (Badger Mining Corporation)
This study aims to demonstrate the true benefit of an innovative salt tolerant high viscosity friction reducer (HVFR) that excels at promoting extended proppant suspension and vertical distribution into the fracture when it is used as a base fluid for the Capillary Bridge Slurry (CBS) and other conventional fracturing fluid systems in combination with nitrogen.
The completion of super-lateral wells now being drilled in tight oil and gas shales in North America, with record lengths close to 4 miles, demand for greater carrying capability of low viscosity (slickwater) fracturing fluids, where significant sand settling can occur before the proppant even reaches the fractures. This has sparked recent interest in the development and application of salt tolerant polyacrylamide-based friction reducers, referred to as High Viscous Friction Reducers (HVFR). The downfall of these first generation HVFR's is the lack of compatibility with high salinity brines such as recycled and flowback water, and diminished ability to reduce friction pressure during hydraulic fracturing treatments when compared to industry standard FR's.
Herein, we report the field application of a unique salt tolerant HVFR (HVFR-ST), that consistently provides higher viscosity values (corresponding industry standard HVFR loading comparison) when tested in brines, without sacrificing friction reduction effectiveness. Additionally, a new concept of fracturing fluid referred to as Capillary Bridge Slurry (CBS) has been successfully implemented in North America, where through a surface modification to the proppant, the addition of a gas phase such as N2, and the use of a polyacrylamide-based friction reducer, the proppant becomes part of the fluid structure and is no longer the burden to be carried. The combination of HVFR's and the surface modified proppant can effectively combat the issues faced with proppant transport in long laterals.
This paper will highlight the results on the analysis of the governing proppant transport mechanisms (suspended and bed) of CBS system formulated with HVFR-ST, in the presence of nitrogen (N2), where no detrimental effect in the average distance traveled of the sand particle in the Proppant Transport Test Bench (PTTB) was observed when the brine concentration of the base fluid was increased from 1% to 5% in comparison to industry standard HVFR (HVFR-FW).
Field production data on wells stimulated with CBS show a significant upside (~ 50%) in liquid hydrocarbon production than offsetting wells over a ~ one year period of time.
Friction loop data carried out at 45 L/min (11.89 gals/min) flow rate in an internal diameter pipe of 0.305" shows a reduction on friction pressure in excess of 70%, when HVFR was tested in 5% API brine (4% (w/v) NaCl and 1% (w/v) CaCl2·2H2O) at loadings as low as 0.1%. Furthermore, dynamic measurements within the viscoelastic regime/behavior of the HVFR at different loadings in the oscillatory viscometer will provide learnings on the elasticity-proppant transport relationship of the different fracturing fluid systems.
Through the use of laboratory testing and field study cases, this paper will illustrate the true benefits on the use of salt tolerant HVFR's as a base fluid with the increasing demand of re-cycled and flowback water use in fracturing fluid systems.
Haustveit, Kyle (Devon Energy) | Almasoodi, Mouin (Devon Energy) | Al-Tailji, Wadhah (CARBO Ceramics Inc.) | Mukherjee, Souvik (CARBO Ceramics Inc.) | Palisch, Terry (CARBO Ceramics Inc.) | Barber, Rusty (Formerly Devon Energy)
What is the number one problem with hydraulic fracturing and the frustrations that haunt every completions engineer? Our inability to see what is going on downhole during and after a hydraulic fracture stimulation job. This deficiency leads to numerous questions when attempting to optimize well performance and drainage, such as fracture extension, height growth, proppant/fluid volume usage, parent well depletion effects, cluster efficiency, etc. Over the years, several technologies have been used in an attempt to answer these questions including fiber optic, micro-seismic, chemical and proppant tracers, pressure matching and modeling. However, to date, none have been able to answer the most basic (and some would argue most important) question of all: where is the proppant located in the far-field?
A novel method that is gaining traction to answer this question is the use of electromagnetic (EM) technology to detect electrically conductive proppant. In this technology, a surface EM array is deployed and the EM field is measured both before and after the electrically-conductive proppant has been placed. Advanced modeling is then used to invert the before- and after-frac response to locate the proppant.
This paper will briefly review the technology as well as the motivation for deploying the process in one operator's STACK development. The paper will then thoroughly review a case history, where this EM proppant detection method was used in two offset infill wells in the STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) play of Oklahoma. The two new wells were selected to be near the parent wellbore, where depletion effects were expected to impact both wells. The primary purpose of the project was to understand the impact the parent well had on an infill stimulation design.
Proppant maps will be presented which address the impact of the parent well depletion on the bi-wing fracture growth. Other complementary technologies will be presented including surface pressure monitoring of offset wells. This technology was also deployed previously in an area vertical science well and where applicable, these results will be included.
This paper will be useful for engineers, geoscientists and other technicians who wrestle with how to effective place their infill wells and design their fracture stimulations, with the goal of optimally depleting their acreage.
The development of unconventional reservoirs require key decisions to be made under uncertainty. We regularly consider multiple variables, such as the number of wells to be placed in a section, their horizontal spacing and vertical staggering, the length and orientation of the laterals, the design of fracturing stages and associated perforations, the quantity and type of fracturing fluid and proppant to use, and geologic variability. These decisions are dependent on the subsurface parameters at each development due to the heterogeneities of rock and fluid properties as well as the nearby historical development. Such complex and dynamic problems combined with the fast pace and large scale of unconventional development pose a significant challenge for classical physics-based reservoir models. We propose a data-driven modeling methodology that is used to support development decisions in the STACK play in Oklahoma.
We utilize multi-variate analytics to model the behaviors of horizontal wells in the STACK (Sooner-Trend-Anadarko-Canadian-Kingfisher) of the Anadarko basin (see Fig. 1 for idealized geologic cross section). The STACK consists of two primary targets, the Meramec shale and the Woodford shale. The Mississippian age Meramec is 200-500’ thick with porosity ranging from 3-6%.The Mississippian/Devonian age Woodford ranges from 75-300’ thick with 3-7% porosity. The Meramec formation consists of several parasequences of fine-grained silts with significant carbonate input in some intervals. Our analysis includes over 500 horizontal wells that target the core intervals in the Meramec. We use these wells in our workflow that predict their production performance impact with respect to both the location of horizontal wells in the STACK trend and multiple engineering variables.
In unconventional resource plays, wells drilled and completed in the same area, within the same target and with the same completions can have results that vary by +/− 50% vs the mean. Without a predictive model to explain this variance, production variability looks like random noise. We chose to use a simple statistical technique called a hypothesis test, and interpret the result using a p-value, a measure of statistical significance. Using the p-value, a trend can be tested to see if the trend in a sample of data is statistically different than the trend that would be expected from a random sample. Several studies have been published on multivariate analytic workflows1,2,3,4.
Dreyer, Daniel (Nalco Champion, An Ecolab Company) | Kurian, Pious (Nalco Champion, An Ecolab Company) | Hu, Thomas (Nalco Champion, An Ecolab Company) | Tonmukayakul, Peng (Nalco Champion, An Ecolab Company) | Calaway, Ronald (Quintana Energy Services) | Hodges, Clint (Quintana Energy Services) | Peoples, Kevin (Quintana Energy Services)
The use of degradable polymeric materials to control fluid flow during hydraulic fracturing (referred to as “diversion”) is an increasing area of interest in well completions. While poly(lactic acid) (PLA) and other similar polyesters dominate the market space, there are drawbacks to these materials that can limit their performance. Specifically, if the particle size distribution is not matched to the geometries of the perforations and fractures, it will be difficult or impossible to achieve optimal plugging/jamming, and the fluid will not be efficiently diverted into un- or under-stimulated portions of the formation. We have developed an alternative approach to fluid diversion that retains the key properties of polymeric diverters, including product degradability and an ability to withstand high hydraulic pressure, while allowing for better sealing efficiency with less sensitivity to the precise particle size distribution. In this paper, we describe a product that is intended for use in lower- to mid-temperature applications (approximately 160-200 °F). Our laboratory and field results show this product can both seal efficiently and adaptably, while also withstanding high hydraulic pressure.
During completion operations, it is typical that only a fraction of the perforations generated will accept stimulation fluid, and then contribute to production once a well is brought online. Estimates vary, but by at least one account, as few as 50% of the perforation clusters are effectively simulated (Miller 2011), leaving significant portions of the formation un- or under-stimulated. As a result, implementation of strategies for the diversion of fracturing fluid during well completions has become increasingly common in field operations (Van Domelen 2017), and one of the more common methods focuses on the application of particulate chemical treatments (Weddle 2017). Commonly referred to as “diverters,” these treatments are typically comprised of blends of controllably, but variably, sized solids that temporarily plug high permeability perforations and/or fractures (Trumble 2019). When these plugs form, the fluid is then redirected into the un- or under-stimulated portions of the reservoir (Allison 2011, Astafyev 2016, Fry 2016, Rahim 2017), ultimately leading to improved production.
High-viscosity friction reducers (HVFRs) have been gaining popularity and increase in use as hydraulic fracturing fluids because HVFRs exhibit numerous advantages such as their ability to carry particles, their promotion of higher fracture conductivity, and their potentially lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs with produced water containing a high level of TDS (Total Dissolved Solids). This study investigates the influence of the use of produced water on the rheological behavior of HVFRs compared to a traditional linear guar gel. This work also aims to correlate proppant settling velocity behavior with rheological properties of HVFRs vs. linear gel on hydraulic fracturing operations. Comprehensive rheological tests of different HVFRs compared with linear gel were performed including, shear-viscosity and dynamic oscillatory-shear measurements using an advanced rheometer.
The results of these rheological measurements reveal that these polyacrylamide-based HVFR systems achieve a high viscosity profile in fresh water with associated high proppant-carrying capacity. On the other hand, increasing water salinity lowers HVFR’s viscosity, increases proppant settling velocity, and lessens the fluid’s proppant-carrying efficiency. Although in fresh water linear gel showed similar viscosity measurements with HVFR-A, the HVFR-A recorded a lower proppant settling rate because HVFR-A has a higher relaxation time (15.3 s) than the relaxation time of linear gel (1.73 s).
As expected, in high-TDS produced water the relaxation time and elastic behavior decreased for all the fracturing fluids tested. HVFR-B recorded the smallest reduction in relaxation time (about 14%) when tested in produced water vs. fresh water, and the resulting settling velocity increased by 29% from 3.4 cm/s to 4.85 cm/s. For linear gel, its reduction in relaxation time exceeded of 70% when changing water salinity from fresh water to high-TDS brine water. This high reduction of relaxation time leads to over 40% increase in proppant settling velocity from 5.3 cm/s to 8.7 cm/s in fresh water and produced water, respectively. This study confirms that HVFR’s elasticity (vs. it viscosity) properties enable successful proppant transport for a wide range of shear rates while viscosity (vs. elasticity) properties controls proppant settling velocity in linear guar-based fluids. This paper will provide greater understanding of the importance of complete viscoelastic characterization of the HVFRs. The findings provide an in-depth understanding of the behavior of HVFRs under high-TDS brine, which could be used as guidance for developing fracturing fluids and for fracture engineers to design and select better friction reducers.
The Devonian-Mississippian STACK/SCOOP Play of the Oklahoma Anadarko Basin is a complex assemblage of tight carbonate and siliciclastic strata and an important oil and gas province. In the last decade, prolific drilling has demonstrated significant heterogeneity in the composition of oils produced from STACK/SCOOP reservoirs. This study discusses possible geoscientific explanations for the heterogeneity observed in produced oils and describes how source, maturation, and migration affect their composition.
Geochemical data from 136 produced oils across 12 counties from 4 producing reservoirs is reviewed. Calculated thermal maturity (Rc%) from alkylated polyaromatic compounds shows excellent agreement with oil thermal maturity increasing with increased depth. Oils produced from overpressured reservoirs exhibit a strong relationship between Rc% and Gas-Oil Ratio (GOR), while normal- to underpressured reservoirs exhibit GORs up to an order of magnitude higher at similar Rc%. Light hydrocarbons show that paraffinicity varies starkly with producing reservoir, suggesting compositional fractionation from diffusive migration through tight and argillaceous strata. Conversely, aromaticity varies geographically by Play Region, indicative of changing depositional environments and organic input across the basin. Isoprenoid and sesquiterpane biomarkers indicate all oils are generated by Type II or Type II/III mixed organic matter, but Springer Group reservoirs are charged by a highly argillaceous, non-Woodford source.
The Anadarko Basin is the deepest sedimentary basin in the cratonic interior of the North America with as much as 40,000 feet of Paleozoic sediments (Johnson, 1989). The Anadarko is an asymmetric basin with the deepest sediments bound against the Amarillo-Wichita Uplift to the southwest. The basin is elongated along its west-northwest axis and bound by the Nemaha Ridge to the east and the Anadarko shelf to the west and north.
In the last decade, drilling of Devonian-Mississippian strata along the margins of the basin have delineated one the continent's most successful petroleum resource plays. These areas are colloquially referred to as the
The Meramec Formation in the STACK play has moved to full field development and multiple wells are put on production in a relatively short time. Our results provide asset teams with key geologic, completions, and operations characteristics and their relative contribution to well performance. Depending on the desired economic metric (NPV or ROR), the drawdown strategy and the magnitude of intra-well interference (fracture to fracture) can be optimized. For instance, if the objective is to maximize rate of return, then tighter fracture spacing may be accepted. Results provide guidance to optimal design parameters and operational strategies in the Meramec Formation.
Optimal cluster spacing has eluded reservoir and completions engineers since the inception of multi-stage hydraulic fracturing. Very small cluster spacing could result in fracture to fracture (intra-well) interference and higher completions cost, whereas very large cluster spacing could lead to inefficient resource recovery which is detrimental to the economics of the well.
This study interrogates the relative contribution of rock matrix, completions, and operational characteristics, vis-a-vis short and long term well performance in tight oil reservoirs. Those characteristics include drawdown strategy, cluster spacing, pressure dependent permeability, critical gas saturation, and petrophysical properties. Available geologic data were integrated to construct a geologic model which will be used to history match a well from the Meramec Formation.
The static model covers an area of 640 acres that encompasses a multi-stage hydraulically fractured horizontal well. The well is unique because it is unbounded and has more than two years of continuous production without being disturbed by offset operations. History match was obtained to three-phase production and flowing bottom-hole pressure. By utilizing element of symmetry, numerical models were created to investigate the effect of fractures interference on short- and long-term oil recovery and producing gas-oil ratio.
Observations from diagnostics such as offset pressure gauges, micro-seismic, fiber optics, and radioactive tracers can provide critical insights into optimal fracture spacing. However, those observations remain incomplete without proper integration with physics-based models to predict well performance and optimize fracture spacing.
Findings suggest that drawdown strategy (aggressive versus conservative) is more impactful to short term oil productivity than fracture spacing. Drawdown strategy is even more impactful on short-term oil recovery than a 20% error in porosity, or water saturation. The profile of producing gas-oil ratio depends on fracture spacing and has been interpreted in the context of linear flow theory.
The Mississippian section, in particular the Meramec and the Devonian Woodford continue to be the preferred investment targets in the SCOOP/STACK trend in Oklahoma We showcase here the seismic characterization of these formations using multicomponent seismic data in the STACK area and the conventional vertical component seismic data in the SCOOP area, using deterministic prestack impedance inversion. The joint impedance inversion carried out over seismic data from the STACK area was used to derive rock-physics parameters (Young's modulus and Poisson's ratio), which showed the sweet spots that are distinct spatially, rather than bleeding off at the edges. The added advantage of joint inversion was that the density attribute could also be derived therefrom, which was not possible for the data from the STACK area. In addition to density, the results from prestack joint impedance inversion have been found to be superior to the simultaneous inversion. The equivalent attributes (besides density) derived for the SCOOP area also show promise.
The Oklahoma SCOOP play extends about 200 miles along the east flank of the Anadarko Basin, and along with the STACK play, have become one of the most active unconventional plays in the US. The trend has gathered attention due to its potential for oil and liquids-rich gas yields, record-setting IP from wells, superior economics and proximity to pipelines and infrastructure. Consequently, oil companies are making huge investments in these plays.
SCOOP is an acronym for
The Meramec and Osage formations in the STACK region of Oklahoma contain varying mixtures of detrital quartz sand and silt, biogenic silica, and authigenic chert phases. Operators in the STACK have experienced drilling delays due to the variability in both the species and spatial location of quartz phases. These delays can involve frequent bit changes, cave-ins, costly side-tracks, and uncertain lateral continuity within the horizontal wellbore.
Thin section petrography is the primary method for characterizing cryptocrystalline quartz, however this method may not be viable in projects with certain time or sample volume constraints. Alternatively, X-ray diffraction (XRD) can be used to provide an estimate for relative proportions of quartz phases. Methods for the study of disorder in quartz crystal structures, by using peak breadths in XRD patterns have existed since the 1970’s. Detrital, monocrystalline quartz grains have well-ordered crystal structures and narrow peaks, whereas chert and sponge spicules have varying degrees of disorder in their crystal structures and consequently have broad peaks. Peak breadths of quartz can be measured to model the average “crystallinity” of quartz phases in a sample, and trends in “crystallinity” can be observed over the length of a well.
Cores of both Meramec and Osage formations were studied to find relationships between depositional environment, lithology, and quartz speciation. The Quartz Crystallinity Index (QCI) calculated from XRD was compared against thin section petrography for validation. Additionally, lateral cuttings from an Osage sidetrack were studied to relate drilling delays to spatial trends in quartz phases.