Gaither Draw Unit is a heterogeneous and tight formation with an average permeability less than 0.1 mD. After more than 1.7 MMSTB water injection, there was no clear indication or benefit of the injected water from any producer. However, knowing the distribution of the injected water is critical for future well planning and quantifying the efficiency of injection. The objective of this study is to show how the Capacitance-Resistance Model (CRM) was used on this field and validated using other independent methods.
The CRM model describes the connectivity and the degree of fluid storage quantitatively between injectors and producers from production and injection rates. Rooted in material balance, signals from injectors to producers can be captured in the CRM. Using constrained nonlinear multivariable optimization techniques, the connectivity is estimated in the selected portion of the field through signal analysis on injection and production rates. In this tight formation, the whole field is divided into seven regions with one injection well and surrounding producers to conduct CRM analysis. We further use integrated but independent approaches to validate the results from CRM. The validation includes full field modeling and history match and fluid level measurement using echometering technology.
This paper focuses on a real field water flooding project in Gaither Draw Units(GDU). CRM is used to detect reservoir heterogeneity through quantifying communication between injectors and producers, and attains a production match. The fitting results of connectivity through CRM indicate permeability regional heterogeneity, which is consistent with full field modelling. The history matched full field model presents the saturation distribution showing that the majority of injected water mainly saturates the surrounding regions of injectors, and the low transmissibility slows down the pressure dissipation. Overall, the comprehensive interpretation obtained through these three independent methods is consistent, and is very useful in planning infill well drilling and future development plan for the Gaither Draw Units.
This paper shows that it is critical to integrate different sources of data in reservoir management through a field case study. The experience and observations from this asset can be applied to other tight formations being developed with water flooding projects.
In recent years, the exploration and production of oil and gas from Bakken formation in Williston Basin have proceeded quickly due to the application of multi-stage fracturing technology in horizontal wells. Knowledge of the rock elastic moduli is important for the horizontal drilling and hydraulic fracturing. Although static moduli obtained by tri-axial compression test are accurate, the procedures are cost expensive and time consuming. Therefore, developing correlation to predict static moduli from dynamic moduli, which is calculated from sonic wave velocities, is meaningful in cutting cost and it makes the unconventional oil and gas exploration and production more efficient.
Literature review indicates such a correlation is not available for Bakken formation. This may be attributed to the extremely low success rate in Bakken core sample preparation and not enough published data to develop correlation to relate dynamic moduli to static moduli. This study measures and compares the moduli obtained from sonic wave velocity tests with deformation tests (tri-axial compression tests) for the samples taken from Bakken formation of Williston Basin, North Dakota, USA. The results show that the dynamic moduli of Bakken samples are considerably different from the static moduli measured by tri-axial compression tests. Correlations are developed based on the static and dynamic moduli of 117 Bakken core samples. The cores used in this study were taken from the core areas of Bakken formation in Williston Basin. Therefore, they are representatives of the Bakken reservoir rock. These correlations can be used to evaluate the uncertainty of Bakken formation elastic moduli estimated from the seismic and/or well log data and adjust to static moduli at a lower cost comparing with conducting static tests. The correlations are crucial to understand the rock geomechanical properties and forecast reservoir performance when no core sample is available for direct measurement of static moduli.
Coring adjacent to a hydraulically fractured horizontal well in Eagle Ford shale by Conoco-Phillips has revealed several closely spaced parallel hydraulic fractures (separated only by few inches) propagating in the direction perpendicular to the wellbore axis. The number of observed hydraulic fractures greatly exceed the number of clusters according to the recent paper titled "Sampling a Stimulated Rock Volume: An Eagle Ford Example". The observed behavior is contrary to the conventional practice of hydraulic fracture modeling where often a single fracture from each perforation cluster. This assumption stems from a simplified concept of the stress shadow that inhibit the growth of multiple parallel fractures under very tight spacing. In this study we show that correct modeling can in fact capture the field observed fracture clusters or swarms of closely-spaced fractures.
Numerical model based on displacement discontinuity method is used to simulate non-planar hydraulic fracture propagation. Fracture deformation, fluid flow and perforation friction are fully coupled. Fracture propagation from a single cluster consisting of 20 perforations under 1800 phasing spanning 5 ft is considered. The effect of controlling parameters such as far-field stress contrast, perforation properties, and fracture toughness on multiple hydraulic fracture growth from a cluster of perforations is studied.
The results show that closely spaced fracture clusters or swarms can occur for a certain range of conditions and operational parameters. The in-situ stress contrast, perforations conditions, and injection rates exert a significant influence. Under the right conditions, closely-spaced fractures can extend to distances exceeding tens of feet from the wellbore. Early termination and/or coalescence of closely spaced fractures can also occur.
To our knowledge, our modeling results are the only ones that can explain the data from the Conoco-Phillips field observations regarding the occurrence of fracture swarms. The resuts show that the assumption of a single fracture per cluster does not hold true under all conditions. Moreover, such assumption would significantly underestimate stimulated rock volume near the wellbore. Finally, our results capture the injection pressure data which can be used as a diagnostic tool to infer the perforation effectiveness (i.e., the number of perforations that are in contact with fluid flow).
Advances in fracture mapping and full 3D modeling have yielded new insights into hydraulic fracture geometry, but it is still impossible to predict height growth. Fracture mapping data collected from a large number of treatments in different basins yield a rule-of-thumb for expected fracture height over fracture length (aspect ratio), but in specific cases fracture design optimization requires a more accurate forecast for height growth. Calibrated models with full 3D fracture geometry will give the best results, but in many projects the available data to calibrate such a model is severely limited. Knowing this, the question this paper attempts to answer is: "Will using a full 3D model give more reliable predictions of fracture geometry (maybe height growth) compared with pseudo-3D models?".
Using data from an instrumented field test and routine fracture treatments, the results of the different fracture models are tested. Even when detailed knowledge of stress and geomechanical properties are available, it is impossible to match observed fracture geometry using only conventional hydraulic fracture physics. So, even a full 3D model does not provide a true prediction of fracture geometry. Both pseudo3D and full 3D fracture models can match observed fracture geometry, but only by introducing additional parameters beyond conventional fracture propagation physics, such as formation lamination or fracture tip pore pressure.
A full 3D model with default input parameters and conventional fracture physics yields a prediction of strong containment, even for modest stress difference between pay and overburden. This agrees in general with average observed geometry, but in specific cases, fracture height growth still occurs, showing that in these cases the model was inadequate and needs to be calibrated. Pseudo-3D models tend to overestimate height growth for default inputs, but that can also be modified to match the stronger containment often seen in practice. Therefore, no benefit is obtained from fully gridded simulation models in routine cases where critical inputs and calibration data are unavailable.
In most US unconventional basins, operators often start development by drilling the minimum number of wells needed to hold their acreage. These initial wells are sometimes called "parent" wells. Operators then start drilling their infill development wells, which many operators are currently in the process of doing across various unconventional basins. Infill performance can be highly variable, with operators making great efforts to ensure infill wells perform comparable to or better than existing parent wells. This challenge will become more magnified in the unconventional industry as infill development surpasses parent well drilling. To add more uncertainty, limited research exists showing basin-wide trends as to how infill wells can be expected to perform on average in comparison to their parent well counterparts. We studied infill well performance in numerous US basins, with the objectives of understanding performance trends and their causes, along with providing recommendations for maximizing infill well potential.
We evaluated the performance of newly drilled infill wells compared to their parent wells, which had been produced for some time. With publicly available production and well information, an evaluation was performed for the following major unconventional basins: Bakken/Three Forks, Barnett, Bone Springs, Eagle Ford, Fayetteville, Haynesville, Marcellus, Niobrara, Wolfcamp (Midland and Delaware Basins), and Woodford.
Using a spatial, statistical approach with key production indicators, we identified key trends across the various basins where the infill wells produced at different production rates compared to their parent wells. Overall, there is about a 50% chance that a child well will outperform a parent well; However, normalizing production to total proppant pumped and lateral length suggests that larger volumes with longer laterals in infill wells may be needed to achieve similar rates to the parent wells.
Underperformance of infill wells may likely be because of existing depletion and inter-well production competition with both parent and other infill wells. Additionally, in areas where significant depletion is expected, predicting the performance of new infill wells can be very difficult. This paper will discuss alternative methodologies and technologies that may help understand and increase the production potential of lower performing infill wells.
Jaime Piedrahita and Roberto Aguilera, Schulich School of Engineering, University of Calgary Summary Quantification of secondary mineralization or cementation within natural fractures has not been considered in previous petrophysical dual-porosity models. This is, however, of paramount importance because morphology of the fractures indicates that they can be open or partially or completely mineralized. If cementation with secondary minerals is complete, the recovery of hydrocarbons will be generally very small because hydrocarbons will not have any way to move from matrix to natural fracture and then to the wellbore. However, if secondary mineralization is partial, production rates and recoveries could be quite significant because the secondary minerals would play the role of natural proppant agents helping to maintain the fractures open as the reservoir is depleted. If the fractures are initially open, production rates and recoveries could be large or small depending on the relative orientation of the natural fractures with respect to in-situ stresses. These observations lead to the key objective of this paper: to develop an analytical dual-porosity model using resistance networks for quantifying petrophysical fracture parameters such as degree of cementation (b), formation factor (F), dual-porosity exponent (m), and tortuosity (s) for different degrees of mineralization (cementation) within the fractures. The method further allows estimating matrix and fracture porosities and fracture compressibility on the basis of the amount of secondary mineralization.
Quantification of secondary mineralization or cementation within natural fractures has not been considered in previous petrophysical dual-porosity models. This is, however, of paramount importance because morphology of the fractures indicates that they can be open or partially or completely mineralized.
If cementation with secondary minerals is complete, the recovery of hydrocarbons will be generally very small because hydrocarbons will not have any way to move from matrix to natural fracture and then to the wellbore. However, if secondary mineralization is partial, production rates and recoveries could be quite significant because the secondary minerals would play the role of natural proppant agents helping to maintain the fractures open as the reservoir is depleted. If the fractures are initially open, production rates and recoveries could be large or small depending on the relative orientation of the natural fractures with respect to in-situ stresses.
These observations lead to the key objective of this paper: to develop an analytical dual-porosity model using resistance networks for quantifying petrophysical fracture parameters such as degree of cementation (ß), formation factor (F), dual-porosity exponent (m), and tortuosity (t) for different degrees of mineralization (cementation) within the fractures. The method further allows estimating matrix and fracture porosities and fracture compressibility on the basis of the amount of secondary mineralization.
Use of the new dual-porosity model is explained with two core data sets drawn from tight gas formations in the United States and Canada. A comparison is made with results of current dual-porosity models that do not take into account secondary mineralization within the natural fractures and tortuosity.
The conclusion is reached that the proposed dual-porosity model provides a valuable new quantitative tool for petrophysical and reservoir-engineering evaluations of naturally fractured reservoirs. This is illustrated with two numerical examples that show determination of original petroleum in place and recovery. One example is volumetric, and the other one is based on the material-balance calculations.
Quantification of secondary mineralization or cementation within natural fractures has not been considered in previous petrophysical dual porosity models. This is however of paramount importance as morphology of the fractures indicates that they can be open, partially or completely mineralized.
If cementation with secondary minerals is complete the recovery of hydrocarbons will be generally very small. If secondary mineralization is partial, production rates and recoveries could be quite significant as the secondary minerals would play the role of natural proppant agents helping to maintain the fractures open as the reservoir is depleted. If the fractures are initially open, production rates and recoveries could be large or small dependent on the orientation of the natural fractures and in-situ stresses.
These observations lead to the key objective of this paper: to develop an analytical dual porosity model for quantifying secondary mineralization (cementation) and tortuosity in natural fractures. The method further allows estimating matrix and fracture porosities, and fracture compressibility based on the amount of secondary mineralization.
Use of the new dual porosity model is explained with two core data sets drawn from tight gas formations in the United States and Canada. A comparison is made with results of current dual porosity models that do not take into account secondary mineralization within the natural fractures and tortuosity.
The conclusion is reached that the proposed dual porosity model provides a valuable new quantitative tool for petrophysical evaluation of naturally fractured reservoirs. In addition, the methodology allows estimating fracture compressibility, a usually elusive parameter needed for estimating original petroleum in place in naturally fractured reservoirs. Although the methodology is explained using data from tight sandstones it also has application in other types of reservoirs and lithologies.
An extensive data collection, training, and field trial program was implemented to develop practices to mitigate a common form of bit damage in hard laminated formations. Analysis improved understanding of the physical phenomena causing the damage and a variety of operational practices and technical redesigns have resulted in reduced levels of bit dysfunction, increased bit life, as well as increased drill rate.
In hard laminated formations, bit life is often limited by severe damage occurring in only the two outside cutter rows on the bit shoulder (
It has generally been observed by the industry that high levels of whirl are rarely seen simultaneously with high stickslip. The observations in the described case are significant in that they may explain those instances where they are seen together. Also, the operations personnel are generally not aware that primary and higher order torsional oscillations may be excited by specific rotary speeds and that new field practices are needed to identify and avoid these in real time. Field trials were conducted that included RPM step tests to determine non-resonant rotational speeds, WOB step tests to avoid the onset of full-stick, bits designed with depth-of-cut control to reduce torsional oscillation, roller reamers to ensure stabilizer drag wasn't contributing to stickslip, and extension of bit gauge length to reduce the lateral movement of the bit in response to lateral force from the BHA.
Direct measurement, using high frequency downhole data, showed it is possible to achieve moderate reduction in bit dysfunction in hard laminated formations through these changes in practices and design. Greater gains might be expected with drillstrings having higher torsional stiffness than the 14,000 ft of 4 inch pipe used in these operations, or with less than the 5500ft of hard laminated formations. In other situations the gains would have been adequate to have enabled a bit to drill an entire interval without tripping. This work may have implications for operations in other unconventional plays, such as the Marcellus, Utica, Niobrara, Permian Basin, Haynesville, Tuscaloosa Marine Shale, and Granite Wash, where laminated formations, small hole sizes, and small diameter drillpipe are common.