Pressure drawdown management (PDM) has been heavily studied in offshore and onshore environments as a way to improve the well productivity and in general Estimated Ultimate Recovery (EUR). There has been a great interest in this topic, especially in unconventional oil and gas reservoirs, where multi-stage hydraulic fracturing and horizontal well technology is used to enhance oil and gas production. Recent studies on Inflow Performance Relationship (IPR) of shale oil/gas reservoirs have shown that unmanaged pressure drawdown (UPD) can potentially impact well productivity and profitability in different ways. Hydraulic fracture conductivity impairment is an example and can occur through proppant crushing, embedment, and fine migration. Uncontrolled pressure drawdown can also cause geo-mechanical effect in high-pressured reservoirs. Aggressive pressure drawdown has shown detrimental impact to EUR, flow capacity, and economics of the wells in Haynesville, Eagleford, and Point Pleasant/Utica shales.
Unmanaged pressure drawdown has also shown rapid transition from transient flow to boundary dominated flow in unconventional gas reservoirs. There is a balance between the rate in which the wells are produced and economic feasibility of the wells over time. Optimal economic production rate must be found for
Characterization of the lateral heterogeneity of reservoir properties is an important consideration during the design of horizontal completion operations in unconventional plays. Traditional geometric designs do not differentiate adjoining rocks based on lateral heterogeneity. This paper presents an academic case study from the Eagle Ford shale play in which the authors analyze and validate an engineering design using observations from an operator's completion design-based fracturing operation. The paper also proposes a low-cost, low-risk solution workflow for these unconventional reservoirs.
An unbiased and repeatable fracture stage and perforation cluster optimization program was used for the engineered design. The input for the engineered design originated from a two-dimensional (2D) petrophysical and geomechanical model. This model was constructed using correlative property modeling that used openhole (OH) logs from an offset vertical well and a calibrated casedhole (CH) pulsed neutron log (PNL) that was acquired in the lateral. A conventional OH logging suite was also run in the same lateral, which was compared to the calibrated log data as a part of the validation process.
The resultant 2D property model provided an appropriate representation of the subsurface reservoir properties. Lateral variations of those properties were duly addressed by optimizing the fracture stage and perforation clusters. This workflow also accounted for the relative position of the wellbore, with respect to the stratigraphic and the reservoir boundaries, as predicted by the 2D property model. During execution of the operator's completion design, reservoir properties were carefully observed and compared with those predicted by the 2D property model and the engineered design derived from the same. These observations validated the properties and justified the optimizations in the completions program and the modifications necessary. For example, a number of stages during the stimulation treatment were initially unsuccessful, thus allowing less than 10% of the total designed proppant to be pumped. During evaluation of the post-stimulation results, it was observed that these zones were identified as less promising by the 2D property model-derived engineered design because of unfavorable reservoir properties. The engineered design model recommended not completing these zones.
The observations from this study showed that completion operations in a long lateral should be designed to account for the lateral variability of the reservoir. The engineered completion design optimized hydraulic fracture stages and perforation clusters based on the petrophysical similarity and merits of the adjoining sections. The methods presented helped mitigate risk and supported rigless operations for characterization in a cost-sensitive environment, thus reducing the costs and effects of hydraulic fracturing operations.
Unconventional reservoirs require hydraulically fractured horizontal wells in order to produce reservoir fluids economically. Induced hydraulic fractures interacting with pre-existing natural fractures results in complex fracture networks (CFNs). Even though hydraulic fracture propagation has been investigated extensively, there is indeed a lack of good understanding of characterization approaches for pre-existing natural fractures. This work presents a practical CFN generation approach by incorporating stochastic algorithms, core, and microseismic data.
Based on analysis of geological structures and core observation, natural fracture density, length, and strike distributions can be obtained. Fracture length follows a power law distribution constrained by minimum, maximum and cutoff lengths as well as a distribution exponent. Fracture strike follows a Fisher distribution. Then, microseismic event locations are used to constrain fracture centers of stochastically generated natural fractures. Moreover, a fast proxy model is developed for hydraulic fracture propagation, which honors both the total mass volume of the pumped proppants, and the pre-defined reference lengths. Finally, a field case study is used to demonstrate how to apply the proposed fracture generation and simulation workflow to model hydraulically fractured horizontal wells.
The proposed workflow implemented stochastic algorithms with the capabilities to incorporate as much information as possible such as core analysis and microseismic information, and to evaluate uncertainties due to pre-existing natural fractures. With the assumption that microseismic event locations are reactivation of pre-existing natural fractures, the perturbed event locations constrained the locations of the natural fracture centers, resulting in a better description of microseismic-derived stimulated reservoir volume. The simplified hydraulic fracture propagation scheme was able to efficiently estimate the resulting complex fracture networks, and to accurately honor the material balance during fracturing treatment. Sensitivity analysis showed that fracture permeability, matrix porosity, and matrix permeability of the CFNs affect well production performance, significantly.
This paper discusses how to utilize available data resources to generate representative CFNs for hydraulically fractured horizontal wells. The process of data preparation for each step of the workflow is discussed in details to facilitate engineers to solve practical problems with the developed methodology.
Pasumarti, Ashwin (Battelle Memorial Institute) | Mishra, Srikanta (Battelle Memorial Institute) | Ganesh, Priya Ravi (Battelle Memorial Institute) | Mawalkar, Sanjay (Battelle Memorial Institute) | Burchwell, Andrew (Battelle Memorial Institute) | Gupta, Neeraj (Battelle Memorial Institute) | Raziperchikolaee, Samin (Battelle Memorial Institute) | Pardini, Rick (Core Energy LLC)
Monitoring an appropriate set of performance metrics is an essential part of a reservoir management strategy that seeks to maximize the efficiency of CO2-EOR floods, and benchmark the performance of the reservoir to other fields in the region. While a number of studies have outlined various options for evaluating the performance of the reservoir, many are not applicable to depleted oilfields that are commonly encumbered with limited data availability. As interest in CO2-EOR grows beyond giving new life to old fields, into a means of reducing anthropogenic CO2 emissions, metrics that enable the analyst to assess the storage capacity of the reservoir in addition to oil recovery efficiency have also become increasingly desirable. This paper will present a streamlined set of metrics that meet these objectives, along with their implementation in a dashboard-style presentation. These metrics provide complementary and non-redundant information, and crucially, are still applicable where a paucity of pressure data exists. The analyst is equipped with four groups of critical information. These are (A) flow rate and cumulative production data; (B) EOR performance trends (incremental oil recovery efficiency, CO2 storage efficiency, and net CO2 utilization factor); (C) operational performance trends (voidage replacement ratio and producing CO2-oil ratio); and (D) storage performance trends (incremental oil recovery factor vs. CO2 storage and CO2 storage capacity vs. voidage). To facilitate comparison, all metrics are normalized to percentage of original hydrocarbon pore volume (HCPV) injected.
The utility of the selected set of metrics is demonstrated with data obtained from CO2-EOR activities in depleted oilfields of the Midwest Regional Carbon Sequestration Partnership (MRCSP) region. First, a nine-panel dashboard is populated using the metrics discussed for the D-33 reservoir, and will be shown to be useful in: quantifying CO2 storage capacity, highlighting reservoir performance parameters (CO2 breakthrough, oil recovery, voidage-related pressure changes during EOR etc.) and identifying CO2-flood maturity. Second, a four-panel dashboard is displayed as a comparative tool across all reservoirs in the region in order to highlight best and worst performing reservoirs and establish representative ranges for reservoir performance. Both dashboards will be useful when comparing performance against averages published in literature.
This work's novelty is attributed to presenting an ideal set of performance metrics by streamlining the numerous options available. A unique dashboard-style presentation is suggested as a means of rapidly assessing oil recovery and CO2-storage performance, and collectively yielding useful insights.
This paper discusses a well-to-well spacing test on a 5 well pad in the Utica Shale that was stimulated with a unique stage sequencing plan. The stage sequencing plan provides an improved understanding of the way that fracture growth can be influenced by subsurface pressure differentials created by newly fractured, shut-in and depleted wells.
Chemical (water) tracers and oil tracers were pumped into the center well of the 5 well pad. The non-traced wells on the pad, along with 2 wells on an adjacent pad, were all sampled during flowback and production. The samples were analyzed for the presence of oil and chemical tracers to determine the extent and degree of well-to-well communication. Additionally, surface microseismic data was collected and used to further assist in the study of the fracture growth. The tracer communication and microseismic data were represented together in a 3D visualization of the well pads.
Generally, the tracers and microseismic events show that there is more extensive fracture growth from a treatment well to offsetting wells when there is no hydraulic pressure barrier between them. Better fracture containment and symmetry was observed on stages that were bounded on both sides by wells that were just fractured. Data from the study show that proper sequencing of the completions can mitigate the tendency for fractures to preferentially grow towards depleted wells.
The study will therefore illustrate the value of tracer and microseismic data for understanding additional or new knowledge about multi-well pad stage sequencing and its role in fracture growth, and overall future well planning strategy.
Xu, Liang (Multi-Chem—A Halliburton Service) | Lord, Paul (Multi-Chem—A Halliburton Service) | Riley, Howard (Multi-Chem—A Halliburton Service) | Koons, Justin (Multi-Chem—A Halliburton Service) | Wauters, Todd (Multi-Chem—A Halliburton Service) | Weiman, Sam (EQT)
Friction reducers (FRs) are an important component for slickwater hydraulic fracturing applications. To continue to effectively treat multiple clusters in longer laterals, even for stages out near the toe area, a robust FR system is typically required to overcome pipe friction. Additionally, it is imperative to be able to use one single FR system throughout the entire treatment that can tolerate various water sources of varying salinity up to 300,000 ppm. This paper discusses the field trials of a new salt-tolerant FR system in the Marcellus shale.
A three-well trial program was initiated in the Marcellus. Various water sources with varying salinities were used with up to 100% re-use of produced water. The operator had not been able to keep the surface treating pressure between 8,000 and 8,500 psi using a standard anionic FR, which typically resulted in a lower pumping rate of less than 100 bbl/min; the first few stages using the standard FR in these wells indicated this was the case. After switching to the new FR, however, the pumping pressure immediately dropped to below 8,500 psi and the pumping rates were increased and maintained at 100 bbl/min.
This new salt-tolerant FR system consists of a water-in-oil cationic polymer and an inverter. Unlike other FRs, the distinctive advantage of the new FR is that the ratio between polymer and inverter can be readily adjusted on the fly to achieve maximum friction reduction. During the pumping operations, it was demonstrated that the inverter was sufficiently quick to invert and release the polymer from oil to water, and the cationic polymer was extremely efficient at reducing additional pipe friction, even with severely impaired water. Additionally, the use of a single FR reduces inventory stock and simplifies on location quality assurance of material usage.
It is well-known that the risk of sanding varies for different completion systems, i.e. open hole versus cased and perforation, in a given wellbore and reservoir. Part of this difference comes from the scale effect of the borehole. Pragmatic approaches are usually taken to consider the borehole scale effect in the sand production prediction analysis. A more rigorous approach is needed to take this effect into account.
Experiments have been conducted by researchers on Thick-Walled Cylinder (TWC) samples with different inner to outer diameter ratios (ID/OD) for samples with standard dimensions (1.5in ID, and 3in length) to investigate the borehole scale effect on the failure of the inner borehole. However, the results partially suffer from the outer boundary effect of the tests and may not purely represent the inner borehole scale effect. Here in this paper, the outer boundary effects of TWC experiments were distinguished from the inner borehole scale effect using analytical approaches followed by extensive laboratory experiments. For this purpose results from comparing different failure criteria (i.e. Mohr-Coulomb, Drucker-Prager, Mogi and modified Lade) from Tehrani's results (2016) were used. Then, the volumetric strain was formulated against confining pressure to explain the elastic, elastic-plastic, and plastic behaviour of the rock.
Variation of TWC strength of samples with different inner borehole sizes may not be fully captured by the analytical approach which only considers the effect of the ID/OD. Hence, the differences between the analytical and experimental approaches can be considered as the inner borehole scale effect. As expected, the analysis showed that the size of the inner borehole and the outer boundaries significantly change the TWC strength of the rock. After distinguishing the outer boundary effects, the results shows a decreasing trend between the inner borehole size and the TWC strength of the sample, which can be considered as the borehole scale effect.
This study has also broadened the understanding of the effect of borehole and boundaries dimensions in TWC test, which may be generalized to real scale cases, i.e. wellbores and perforations.
Studying kerogen structure and its interactions with fluids is important for understanding the mechanisms involved in storage and production of hydrocarbons from shale. In this study, adsorption and transport of methane in a three dimensional type II kerogen model are studied using molecular dynamics simulations.
Grand Canonical Monte Carlo (GCMC) simulations are used to simulate the adsorption of methane and NonEquilibrium Molecular Dynamics (NEMD) simulations are employed to simulate transport of methane in the kerogen model. The kerogen model prepared by
Nanomaterials are the new additives for drilling fluids that can improve its properties and eliminate problems due to increased downtime and well costs. The objective of this research is to select the optimum concentration of nanoparticles that enhance drilling fluid properties and hydraulics. This study investigates the effects of commercially available nanoparticles on the rheological and filtration properties and optimizes the hydraulics of water-based drilling fluids.
In this study, the samples were prepared as water-based muds with and without various concentrations of 5.7 nm colloidal silica dioxide nanoparticles. Series of laboratory experiments were carried out for all samples using standard API Low Pressure Low Temperature (LPLT) filtration and rheological tests. Two mud systems at different pH conditions were used to evaluate the impact of nanoparticles. A commercial software was used to evaluate the impact of the nanoparticles on the Equivalent Circulation Density (ECD) and the circulation pressure loss in a deviated wellbore.
Results show enhancements in the rheological and filtration properties for water-based muds treated by the nanoparticles used in this study with concentrations below 0.7% by weight. Furthermore, the results show the ability of these nanoparticles to make the filter cake consistent, compacted, and thin. The results reflect the negative impact of the nanoparticles with concentrations above 0.7% by weight on some of the rheological properties. The optimum nanomaterial concentrations with the best properties were observed as (0.1%-0.3%) by weight. Furthermore, the concentration of 0.1% by weight reflected the significant reduction in the ECD and the circulating pressure loss.
Nanoparticles used in this research can play a vital role in reducing drilling problems. Multilateral wells, slim holes and deep horizontal wells can be drilled by using water-based mud with the addition of proper nanoparticles and eliminating the need for oil-based muds that are expensive and environmentally unacceptable. However, it is critical to select the proper size and concentration of nanoparticles in order to eliminate its negative impact on the drilling fluid properties.
The Dry Utica play is an exciting unconventional gas development currently unfolding in the Appalachian Basin. Published results for several wells exceed an average Initial Production (IP) rate of 60 MMcf/day. However, complexities in the reservoir can make the developmental learning curve steep. Challenges include true vertical depths (TVDs) of 9,000 to 13,500 feet, pore pressures of 0.8 to 0.99 psi/ft, and bottom hole temperatures of up to 240 degrees Fahrenheit. In addition, the reservoir has high stresses, high closure pressures, complex and varying mineralogies. Among the greatest challenges in Dry Utica field development is cost effective proppant and frac fluid design and selection. In order to achieve an adequate return on investment: Proppant design has to be optimized to withstand high pore and closure pressures and overall high stresses, but also be cost effective. Frac fluid design has to be compatible with varying mineralogies to avoid a steep decrease in fracture conductivity.
Proppant design has to be optimized to withstand high pore and closure pressures and overall high stresses, but also be cost effective.
Frac fluid design has to be compatible with varying mineralogies to avoid a steep decrease in fracture conductivity.
This paper discusses field testing of proppant design and selection and how cost, geological, reservoir, and rock properties affect the completion design and well production. The paper will also review frac fluid design used for proppant transportation and placement, and potential issues with formation mineralogies, as well as mitigation. Field case histories with managed production draw down and how that can affect proppant inside a fracture will also be reviewed.