Improved completion design and field development strategies have provided commodity price resilience by sustained efficiency gains across most major US Shale plays. This rapid evolution in completion practices, however, has created behind pipe opportunities. Refracturing offers a viable solution to maximize on these opportunities, however, its effectiveness is dependent on a variety of factors. The present paper explores the implementation of refracturing as a re-development strategy in legacy shale plays and evaluates it as a truly multivariable problem.
The paper takes into consideration petrophysical parameters, initial completion design, chemical composition, formation quality, time from original completion, refrac completion design and production performance to quantify impact on refrac KPIs such as IP ratio, EUR ratio, decline trend impact, amongst others. The paper does this by using an ACE (alternating conditional expectation) non-linear regression model that incorporates the KPI’s as response variables and utilizes the transforms of a wide range of input variables to identify cause and effect relationships. By running this analysis across multiple legacy shale plays, including the Haynesville, and Barnett, the paper provides best-practices to maximize refracturing success.
While refrac can offer a viable solution in obtaining incremental production, depending on the basin, a refrac can be a tenth of the expense of a new well and can beneficially impact the production from the existing well. In most cases, the analysis found EUR predictions improved by 30% - 200%. While correlations varied across basins and completion design, an inverse correlation was found between refrac KPIs and initial frac intensity.
Although, refracturing in horizontal shale wells is a well-established practice, a significant amount of analysis on their performance is focused on one or two key variables. The present paper adds to the existing body of literature by using data analytics and machine learning to evaluate this strategy from a truly multivariable standpoint. The paper also provides best practices to evaluate and predict refrac performance to de-risk refrac as a field re-development strategy.
Low injected fracturing fluid recovery has been an issue during flowback period that is highly impacted by the fracture closure behavior. Although existing flowback models consider fracture closure volumetrically, they do not represent the true situation of non-uniform fracture closure. In this paper, we proposed a coupled geomechanics and fluid flow model for early-time flowback in shale oil reservoirs. The fluid flow model is coupled with an elastic fracture closure model through finite element methods. In this study, three stages are modeled: fracture propagation, well shut-in and flowback. Cohesive Zone Method (CZM) has been used for modeling fracture propagation. The presented model distinguished the propped part from the unpropped part of the fracture. At the beginning of flowback, the proppants may not be completely compacted in early shut-in time. Thus, permeability evolution during closure is tracked using a smooth permeability transition function. The numerical results have shown that fracture closure during the flowback period is often not uniform. While the uniform fracture closure leads to maximum fracturing fluid recovery, an aggressive pressure drawdown strategy may damage fracture connectivity to the wellbore. An integrated flowback model enables modelling nonuniform fracture closure in a complex fracture network. This study highlights that by choke/pressure drawdown management, operators can influence fluid recovery and even maintain high fracture conductivity. Furthermore, the methodology presented in the paper can also be used for inverse analysis on early flowback data.
Production data and analytical models derived from coupling the linear flow in the reservoir and the linear flow in hydraulic fractures were used in this study to optimize fracture spacing for maximizing productivity of shale oil and gas wells through refracturing. This study concludes that productivity of multi-fractured horizontal wells is inversely proportional to the fracture spacing. The shortest possible fracture spacing should be used to maximize well productivity through refracturing. This supports the practice of massive volume fracturing where as many as perforation clusters with the shortest possible spacing are used for pumping massive proppant into the created hydraulic fractures. Production data analysis indicates that the multi-fractured horizontal oil and gas wells could have higher productivity if they were fractured with less perforation cluster spacing. Mathematical model analysis implies that reducing the cluster spacing from 70 f t t o 15 f t t h r o u g h r e f r a c t u r i n g c a n d o u b l e d w e l l p r o d u c t i v i t y, w i t h t h e M i n i m u m Re q u i r e d C l u s t e r S p a c i n g (MRCS) determined by well completion constraints (packers, perforation clusters, and casing couplings). Result can be checked for fracture trend interference on the basis of analyses of pressure transient data or production data.
Hydraulic fracturing is a typical and vital technique applied in shale gas reservoir development. Numerical simulation used to be a common tool to optimize the parameters in hydraulic fracturing design determining the stage numbers, injection pressure, proppant amount, etc. However, the current understanding of shale gas storage and transport mechanism (e.g. adsorption/desorption, diffusion) is basically adopted from the lessons learned from coal seams through past experience, which might not help an efficient numerical simulation development.
In this study, how artificial intelligence assisted data driven models assist the hydraulic fracturing design in shale gas reservoir is discussed. It starts by collecting field data and generate a spatial-temporal database including reservoir characteristics, operational/production information, completion/stimulation data and other variables, Neural Network models are then developed to study the impacts of all parameters on gas production as well as perform history matching of the field history. The AI assisted model with acceptable matching of field data can be used to model different hydraulic fracturing design scenarios and provide predictions on well production.
The current scheme for developing shale reservoirs necessitates special considerations while estimating the reserve. While reservoir characteristics lead to an extended infinite acting flow regime, completion schemes could result in a series of linear flows. Therefore, the initial linear flow does not have to be followed by a boundary-dominated flow. Overlooking this observation leads to unphysical Arps’ exponents and overestimations of the Estimated Ultimate Recovery (EUR). We are proposing a workflow to overcome these challenges and honor the inherited uncertainty while using the classic
Underbalanced drilling via air drilling is deeply rooted in the Northeast United States due to its distinct geology, high rates of penetration (ROP) and drilling efficiency, and low cost of circulating material. The active drilling programs of several independent operators in the Marcellus and Utica Basins are well suited for air drilling down to the final kick off point by virtue of competent, stable formations, low static reservoir pressures, and manageable water ingress to the wells. Air drilling provides near-atmospheric pressure at the borehole bottom, since there is no fluid column with resulting hydrostatic pressure. The result is very high ROP with essentially 100% drilling efficiency, allowing the completion of intervals in one or two bit runs. A service company deployed a cross-functional product development team to optimize oilfield air bits for these applications over the last two years, resulting in decreased drilling costs through increased performance and reliability.
The oilfield air drilling environment places unique challenges on drill bit design due to the increased risk of downhole vibrations, corrosion, abrasive wear, heat generation, and seal infiltration of very fine cuttings. The application requirements have increased due to deeper intervals requiring passage through multiple high unconfined compressive strength formations, extended tangent angles, and rising input energy levels. Accordingly, enhancements to both the cutting structures and sealed bearing systems were vigorously pursued. Several cutting structure design iterations were evaluated in both laboratory and field tests. A new sealed bearing system was developed and implemented for increased life and reliability. Modifications to the bit body for stability were included, and the bit hydraulics were further optimized.
Through an understanding of the objectives and application challenges, unique solutions were developed for Northeast oilfield air drilling applications. The optimization process for the new air bit designs is described, and the resulting positive performance metrics are presented. Improvements were observed in distance drilled, ROP, seal effective rate, and dull condition. Lessons learned were also used to refine the recommended drilling parameters and practices through the challenging formations encountered in these tangent sections, which can span in excess of 7000 feet. These enhancements all contributed to reduced drilling cost and days per well, for increased rig productivity.
The natural gas fields throughout the Marcellus and Utica Basins in the Northeast U.S. continue to deliver rising total gas production for the U.S. and the world through increased capacities in pipelines and LNG trains. Improved drilling performance as documented in this paper are driving continuous improvement in the overall upstream drilling economics of the region.
The acquisition of downhole pressure data representative of reservoir response enabling subsequent pressure transient analysis has been one of the primary drivers for running drill stem tests. However, many factors can influence the representativity and interpretability of the data acquired that are not related to reservoir properties.
To our knowledge, while many publications have presented challenges in acquiring representative pressure data those have not been compiled in a comprehensive revies, and there are no practical recommendations that would summarise causes and effects and offer procedures to eliminate or at least manage those effects and enable end-users to maximize the value of acquired data.
This paper describes in details today's challenges associated with the acquisition of high-quality, representative and undisturbed bottom hole pressure data during well test operations. Many different effects, including gauges’ deployment methods, wellbore effects and operational aspects of the test can compromise the quality of bottom hole data acquired while running a welltest.
Therefore, the origin and impact of each of these effects needs to be evaluated at the design stage of the test to develop appropriate mitigation actions. To address these issues, actual examples and methodologies derived from various locations are presented.
Over the years the metrological performances of downhole memory gauges such as resolution or drift have improved drastically, reaching a point where gauge specifications have become less influential on data quality than environmental effects. Many improvements have also been made in DST tools to increase the representativity and interpretability of acquired bottom hole pressure data such as the introduction of downhole shut-in valves or compensation for tubing contraction and expansion due to temperature change during the test. However, there remain several occurrences today where memory gauge data are affected by the various wellbore phenomena making interpretation of downhole pressure transient test data complicated. The selection of an appropriate location of pressure sensors in the DST string also remains a crucial task.
The paper provides analysis, explanations and practical recommendations allowing to mitigate the most common effects typically observed during welltest operations performed around the world, such as: Tidal effect Fluid segregation effect in the wellbore Pressure noise propagation from the surface due to rig movement The impact of application of electrical submersible pump (ESP) on the quality of pressure build-up data "Hammer effects" during well shut-in Impact of circulation above the test valve during PBU Impact of pressure bleed off and top up in the annulus Fluid cooling effect in the wellbore Gauge movement due to string contraction and expansion
Fluid segregation effect in the wellbore
Pressure noise propagation from the surface due to rig movement
The impact of application of electrical submersible pump (ESP) on the quality of pressure build-up data
"Hammer effects" during well shut-in
Impact of circulation above the test valve during PBU
Impact of pressure bleed off and top up in the annulus
Fluid cooling effect in the wellbore
Gauge movement due to string contraction and expansion
This paper will summarise the observation and lessons learned from hundreds of welltest operations performed around the globe with different reservoir fluids and environments through a few telling examples. Furthermore, the paper provides practically proven well-test techniques allowing to manage those adverse effects on bottom-hole pressure data. Recipes for success are provided to ensure that high-quality data can be acquired during welltest operations in a challenging environment while keeping the cost in line with the AFEs.
Out-Of-Sequence (OOS) Fracturing can potentially maximize reservoir contact and fracture conductivity/connectivity by creating fracture complexity via reducing the stress anisotropy. It is initiated by fracturing two "book-end" frac stages (Outside Fracs), followed by a ‘middle" stage (Centre Frac) between them. The Center Frac is theorized to utilize the reduced stress anisotropy to activate pre-existing failure surfaces oriented at various azimuths and dip angles, thereby connecting bi-wing fractures to planes of weakness (natural fractures/fissures/faults/joints/cleats) and resulting in a complex fracture network that enhances connectivity and fracture area within the Stimulated Reservoir Volume (SRV). OOS Fracturing can mitigate possible issues in treatments aiming at creating fracture complexity, including zipper frac (fracture tip interference and blunting inhibiting fracture extension), modified zipper frac (risks of well bashing and fractures growing asymmetrically opposite of the induced stress from prior stage in the adjacent well), simultaneous frac (middle clusters experiencing larger stress interference inhibiting their growth), and high-rate fracturing (risk of cluster erosion reducing the limited entry effect and premature screenout due to inconsistent diversions inside fractures).
Since its inception in early 2010s, OOS Fracturing has not gained considerable attention due to previously-existing operational limitations in fracturing out-of-sequence. It is reported to have been field tested in Western Siberia in 2014 with claimed well performance success. Operational limitations of the system employed in that trial is believed to have prevented its commercial development at that time. With the advent of Multicycle Sleeves and Shift-Frac-Close operation with a single Bottom-Hole Assembly to open and close sleeves, previous operational limitations of OOS Fracturing have been resolved. OOS Fracturing has since been trialed in three formations in Western Canada (2017/2018). This work analyzes the fracture treatment pressures and well performance of these trials.
Five OOS Fracturing trials in these three formations reveal that normalized 15-month/18-month production from out-of-sequence-fractured wells outperform that of sequentially-fractured offsets, with similar formation properties and treatment designs. Instantaneous Shut-In Pressures (ISIP) of Centre Frac are generally higher than that of either Outside Fracs. Breakdown pressures for Centre Fracs exhibit a mixed trend, confirming that reducing stress anisotropy could lower the breakdown gradient (based on Kirsch Equation) if rock fabric permits. Well performance and treatment pressures appear to be more sensitive to Centre Frac proppant tonnage/fluid volumes and uneven sleeve spacing.
This is the first attempt in analyzing the five OOS Fracturing trials, with encouraging well performance and operational execution in conventional reservoirs where it was deployed. Despite uneven sleeve spacing, depletion due to offset production, and less favorable geomechanical properties (high Poisson’s Ratio and low Young’s Modulus), field trials produced favorable results. True potential of non-sequential fracturing is potentially more promising in unconventional reservoirs with formation properties more conducive to complex fracture generation.
Development of reliable models for hydrocarbon-in-place and water saturation estimation requires knowledge about wettability of mudrocks and the parameters (including rock properties and reservoir condition) affecting it. A significant volume fraction of organic-rich mudrocks is composed of kerogen. Therefore, wettability of kerogen affects the overall wettability of organic-rich mudrocks. The chemical composition and structure of kerogen varies with kerogen type and thermal maturity, which affects the surface properties of kerogen such as wettability. In a recent publication, we demonstrated using experimental techniques that kerogen could be water-wet at low thermal maturities and oil-wet at higher thermal maturities. However, the impacts of kerogen type and reservoir temperature/pressure conditions on kerogen and mudrock wettability is yet to be quantified. Therefore, the objectives of this paper include (i) quantifying the impacts of kerogen molecular structure and composition on water adsorption capacities, (ii) quantifying the impacts of reservoir pressure and temperature on water adsorption capacity of kerogen using molecular dynamics (MD) simulations.
In order to achieve the aforementioned objectives, we use a combination of molecular dynamics simulations and experimental work. The inputs to the molecular dynamics simulations include realistic models of kerogen, which are condensed to porous kerogen structures. Water molecules are filled in kerogen pore structure and MD simulation is performed. The outputs of the simulations include radial distribution function (RDF), and adsorption isotherms of water on kerogen for different kerogen types, thermal maturities, and temperature conditions. The adsorption processes are modelled for pressure and temperature conditions ranging from 0 to 35 MPa and 320 to 370 K, respectively. The outcomes of molecular dynamics simulations demonstrated that the water adsorption capacities of kerogen vary significantly with kerogen type, thermal maturity, and temperature and pressure conditions. The RDF results showed that the water adsorption capacity decreased from type I to type III kerogen. The water adsorption capacity of kerogen was found to increase by 128% with 38% increase in oxygen content. The increase in the adsorption capacity was attributed to the strong attraction between oxygen containing functional groups in kerogen and water. The adsorption isotherms of water and kerogen samples showed that the water adsorption capacity decreased by 0.19 mmol/g as the temperature increased from 320 K to 370 K. The average water adsorption capacity of kerogen was found to increase by 20% with increase in pressure by 34 MPa. The results obtained from molecular dynamics simulations were found to be in good agreement with experimental results. The results of this paper can be used to predict the adsorption capacities of any kerogen with the availability of geochemical information. This important property of kerogen is required for estimating kerogen wettability and can enhance understanding of fluid-flow mechanisms in organic-rich mudrocks.
Well drainage areas and shapes for wells in reservoirs with aquifer contact or gas-oil contact (constant pressure boundary) take varying shapes, such as, water coming from one-side (edge water drive) to water coming from 3-sides when the 4th-side is a sealing fault. This information is important in well test interpretations, peripheral flooding, aquifer injection, gas and CO2 aquifer storage, geothermal reservoirs, and any subsurface recovery schemes involving injection-production well pairs. A knowledge of well drainage shapes is helpful in optimizing well placement, well productivity estimations, and to maximize reserves. Results show that for a 2-well 3-sided water-drive reservoir system, each well drains an equal area when the well-rates are equal; however, the drainage areas of a well increases logarithmically with an increasing ratio of its flow rate to that of an adjacent well. In case of a multiple well system, results show that the drainage area of well closer to water contact is smaller than that of an interior well, farther away from the water-contact. Results are presented in graphical form and equations to determine the drainage area and shapes for varying production rate-ratios between wells in a multiple constant pressure boundary rectangular reservoir. An algebraic procedure is presented to generalize results from a 2-well system for extension to a multi-well system with similar multiple constant pressure boundary conditions. The equations yield result within 5% of those obtained from complex streamline simulations. A well's location within its drainage area is needed to determine mean well pressures from MBH (Matthews-Brons-Hazebroek) functions for water drive reservoirs, and to estimate productivity index and cumulative water influx volumes.