Geosteering has relied on manual log interpretation for decades. This paper outlines a new, patent-pending method of automated geosteering dubbed Cybersteering. By utilizing a graph database spatially and assessing the quality of gamma matching for a large catalog of potential segments of constant bed dip (strat blocks), a geosteer can in many cases be constructed that closely mimics that of a manual steer. The Cybersteering proof of concept has the ability to lighten geosteering workloads while increasing productivity and accuracy of geosteers.
Geosteering as a system and method for controlling a wellbore based on downhole geological measurements to stay within a pay zone originally rose to prominence in US onshore drilling in the late 1980s and early 1990s (Lesso, Jr.). Wells came to be steered with gamma ray once logging-while-drilling and measurement-while-drilling tools became more common, although steering based off of rate of penetration and mud samples was also common. Innovations since then have included the utilization of resistivity logs, various uses of seismic data, as well as experimentation with technologies such as mass spectrometry and x-ray diffraction (Durham). However, there has yet to be as large an advancement in geosteering as the initial move from the tedious analysis of paper logs to software that can display data graphically. Within such software, geosteerers can stretch or squeeze gamma ray log sections to match a total vertical depth (TVD) type log from a nearby well in order to correlate a well's stratigraphic depth. The general process requires a geosteerer to review gamma and trajectory data every time a survey comes in and visually determine the best overall gamma match between wellbore and type log through the manipulation of strat blocks, which are sections of constant bed dip. The gamma match is changed and determined by manually varying strat block length and angles (Stoner). A typical geosteering screenshot is shown in figure 1.
This is the second of a three-part tutorial describing a workflow for evaluating unconventional resources including organic mudstones and tight siltstones. Part 1 reviewed the unique challenges and provided an overview of the proposed workflow (Newsham et al., 2019). Part 2 describes in detail the many components of the workflow and how they come together to determine the storage capacity of the reservoir. Part 3 links the petrophysical results to the production potential in terms of fractional flow and water cut and will present alternate cross-checks of the storage properties to validate the results.
As stated in Part 1, one of the most important functions that the petrophysicist provides is the estimation of accurate storage properties. However, when the authors survey the range of workflows used to estimate the storage capacity of these complex systems, we find a wide range of options. Solutions can vary from simple deterministic to more complex probabilistic approaches. Whatever the method, the objective should be the same: to provide consistent, portable hence reliable estimation of hydrocarbon storage capacity, also known as “Petrophysics CPR.” As mentioned in Part 1, estimation of hydrocarbon storage is more than just the calculation of porosity and water saturation. In this tutorial, we will describe a workflow that has been successfully used to evaluate thousands of wells in the Permian Basin with great consistency. The authors have nearly 100 wells with core data to calibrate the workflow. We will show examples of the workflow’s portability by highlighting examples from the Midland Basin, the Texas Delaware Basin and the New Mexico Delaware Basin. We will show how every property measured in core matches to log-based profiles using a combination of deterministic and the constrained simultaneous solution methods. The workflow also is found to be reliable in other basins throughout the world, however, the examples will be confined to the Permian Basins.
This is a three-part tutorial of a workflow for evaluating unconventional resources including organic mudstones and tight siltstones. Part 1 reviews the unique challenges and we provide an overview of the proposed workflow. Part 2 describes in more detail the many components of the workflow and how they come together to determine the storage capacity of the reservoir. Finally, Part 3 links the petrophysical results to the production potential in terms of fractional flow and water cut.
One of the most important functions that the petrophysicist provides is the estimation of accurate storage properties. In the oil and gas industry, storage defines the opportunity, and flow pays the bills. Estimation of storage is more than just estimation of porosity and water saturation. It begins with accurate assessment of rock composition which begets accurate porosity and subsequently water saturation. However, storage estimation need not end there. With an understanding of fluid type and properties, and with the application of appropriate equations of state that describe the variation of formation volume factor, bubblepoint or dewpoint pressure, oil viscosity and density as a function of temperature, pressure, GOR, API gravity and gas gravity, very accurate assessments of oil in place (OIP), gas in place (GIP), and water in place (WIP) are possible in profile. These profiles are then integrated into cumulative storage volumes by bench.
Well-to-well interference or communication between the production or "Parent" well and the infill or "child" well is one of the main concern in horizontal wells refracturing, which results in a decrease of productivity of both the wells. Many field observations have demonstrated that the "child" well fractures could have a tendency to propagate towards the "parent" well resulting in well-to-well interference or "frac-hits" issues. This paper presents a geomechanical perspective to better understand the problem of "frac-hits" in horizontal well refracturing and to design solutions for it using geomechanics analysis and modeling. The numerical analysis is based on a fully coupled 3D model "GeoFrac3D" with the capabilities to simulate multistage fracturing of multiple horizontal wells. The model fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The modeling results show that production from the parent well gives rise to a non-uniform reduction of the reservoir pore pressure around the production fractures leading to anisotropic decrease of the reservoir total stresses which may result in stress reorientation or reversal. The decrease of total stresses in the vicinity of the parent well fractures creates an attraction zone for the child well fractures. The child well fractures have a tendency for asymmetric growth towards the lower stress zone. The impact on the parent and child well production and the risk of "frac-hits" will vary with the reservoir stress regime and production time. Optimizing fracture and well spacing, fluid viscosity, and the timing of refracturing can help to minimize problems. The simulation results demonstrate that the risks of "frac-hits" issue can be mitigated by re-pressurization of the parent well before child well. Traditional methods of refracturing simulation usually use two different codes to solve the problem and mostly use stress analysis rather than explicit fracture propagation. The model used in this study can simulate both aspects of the problem i.e., the reservoir depletion analysis and the subsequent child well fracturing.
Standard hydraulic fracturing jobs in the petroleum industry involve massive injections of water to induce and propagate new tensile fractures at treatment pressures much higher than the minimum principal stress. Proppant is then used to support the induced conductive fractures.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC.
Though representing only a small percentage of the artificial lift systems in their fleet, electric submersible pump (ESP) repairs are an incredibly expensive issue at Devon Energy. In an effort to better understand ESP behavior and potentially delay these failures in the future, the Advanced Analytics team and the Production Operations team collaborated to statistically identify the key drivers behind ESP failures and determine if it was possible to accurately predict an ESP’s lifespan using predictive model techniques. Continuous time series data from PI was summarized over ESP lifetime and combined with static descriptive data from Wellview in fifty-three ESPs across the Delaware Basin. Data exploration was performed in SAS Enterprise Guide before a number of predictive models were created in SAS Enterprise Miner.
Model competition was performed using a variety of modeling types such as linear regression, decision trees, and high performance random forests (HP Forest). The best model, the HP Forest model, was selected based on average square error. The HP Forest model predicted ESP lifespans which were, on average, within approximately five days of the true ESP lifespan. 90% of the model’s predictive error were within +/- 30 days of the true ESP lifespan. The top three variables of importance when predicting ESP lifespan were metrics related to ESP shutdowns. Other notable variables included those related to proppant size and amount. These results prove that it is possible to create an appreciably accurate statistical model to predict ESP lifetime using static summarized data. After further standardization and optimization, this model may be operationalized in the future. This modeling process may also serve as the basis for future modeling exercises using unsummarized continuous time series data. Key driver analysis highlighted the influence that ESP shutdowns have on the lifespan on an ESP. Since ESPs can be shut down as a response to mechanical or human interference, analysis of ESP shutdowns using pattern recognition analysis and chaos theory may be performed in the future.
The Woodford Shale in Oklahoma is one of the most prolific unconventional petroleum reservoirs in the United States. Within the study area, the petroleum produced from this reservoir is self-sourced with a significant component having migrated in from deeper in the basin. It is hypothesized that oils migrated in an up-dip direction, but the extent of this migration has not been well documented. This study provides new insights as to the extent of this self-sourced petroleum and its characteristic phase behavior. Source rock maturity, carbon isotopes, produced oil chemistry, and biomarker ratios were all analyzed and compared to better understand migration and self-sourcing in the study area.
This geochemical work was performed on well cuttings, cores and oils extracted from source rocks; as well as produced oils from the reservoir. Sampled Woodford organic-rich shales contain very little vitrinite; however, they contain abundant solid bitumen. Thermal maturity data from solid bitumen were converted to a vitrinite reflectance equivalent (Jacob, 1989) and compared with pyrolysis data (e.g. Tmax and Hydrogen Index). Both methods were found to be in excellent agreement. Source rock maturities vary across the area of study from early oil (~0.70 % Ro) to gas windows (~>1.35 %) and approximately follow the present-day structural depth of the Woodford source rock.
Produced oil geochemistry data (specifically bulk molecular compositions, isoprenoid distributions, saturate and aromatic carbon isotopes, and biomarker ratios) from several wells suggest a common Woodford source; however, the oil maturities (e.g. Ro equivalent from biomarkers) are significantly higher than the Woodford source rock in many locations. Furthermore, the predicted GOR (gas-to-oil ratio) values from the same oil chemistry data are well matched with the produced GOR and estimated GOR from the recombined fluid samples. These findings support the interpretation that production from several Woodford wells includes migrated hydrocarbons from a deeper source. This study highlights two important ways in which geochemistry can be used to better evaluate source rock reservoirs: 1) by identifying the existence and extent of hydrocarbon migration, and 2) by predicting and understanding the quality and type of petroleum fluids stored in tight, unconventional source rocks. The approaches described in this paper can be utilized to predict, understand, and more accurately classify unconventional reservoirs all over the world.
Shear slip caused by increased pore pressure due to injection has been explored as a mechanism for permeability enhancement of unconventional hydrocarbon reservoirs. The process reactivates pre-existing fractures around a hydraulic fracture causing them to slip and dilate and can also cause fracture propagation in the shear and tensile modes creating secondary cracks resulting in increased permeability. Control and optimization of shear stimulation can be achieved by studying how fluid flows through fractures as the stresses (shear and normal) change and how fracture permeability evolves with slip. However, laboratory data on fluid flow and fracture slip in reservoir rocks particularly shale rocks are rare, and the mechanisms of permeability evaluation with shear slip and dilation are still not well understood. In this paper, we present the results of a laboratory scale testing program to address these questions. Salt water (7% kcl) was injected into the two Eagle Ford shale samples under triaxial conditions having a single natural or an induced tensile fracture to induce shear slip, and flow rates during shear slip processes were measured to characterize fracture permeability evolution. In addition, fluid flow through shale fractures under different values of confining stress and injection pressure were examined to investigate the stress-dependent permeability of shale fractures. The hydrostatic flow tests show that flow rate linearly rises with the increase of injection, while an exponential relationship can be observed between flow rate and effective confining pressure. In the injection-driven shear tests, we achieved 6 to 15 times increase in flow rate even with only small shear sliding (<0.1 mm) induced. In addition, permeability tends to linearly evolve with the increase of shear slip and normal dilation. The results quantify the role of shear slip in enhancing permeability of shale fractures, and would help engineer solutions for maintaining these fractures open, reducing costs (proppant/water and additive cost savings).
Brady, Jared (Devon Energy Corporation) | Daal, Johan A. (Devon Energy Corporation) | Marsh, Kevan (Devon Energy Corporation) | Stokes, Trevor (Devon Energy Corporation) | Vajjha, Pavan (Devon Energy Corporation) | Werline, Rusty (Devon Energy Corporation) | Williams, Chris (Devon Energy Corporation)
During a low commodity price environment operators look for ways to increase production with very little capital. One of the approaches includes re-stimulating or re-fracturing an already producing well to improve its production and value.
Re-fracturing horizontal wells in unconventional formations is still in its infancy. There is lack of consensus regarding techniques used for candidate selection and execution, and results have been enigmatic at best. Some of the most common concerns include zonal isolation, diversion agents, costs, field execution and financial returns.
The Barnett Shale in Texas played a key role in unlocking vast amounts of hydrocarbons around the world. This basin is already considered mature, and re-fracs have already been attempted in vertical and horizontal wells of different vintages.
This effort focuses on the Barnett Shale, and shows the effect that restimulation has on reserves. Field examples are used to illustrate the benefits and risks involved in these operations. This paper will discuss an integrated approach to candidate selection, re-completion methodologies, and an interpretation of results by understanding the rate-transient response of the well.
The Barnett Shale formation is located in the Fort Worth Basin of north-central Texas (Figure 1) and has been developed as a horizontal play since the early 2000’s. In Devon’s core area, the Barnett formation averages 60 feet of Upper Barnett shale and over 275 feet of Lower Barnett shale which is separated by the Forestburg Lime. A type log is shown in Figure 2. The Barnett shale averages 5 – 6% porosity with a 25% water saturation is slightly over-pressured. Devon Energy operates 5,000 Barnett Shale producers, with over 3,000 horizontals and nearly 2,000 vertical completions. Since the early 2000’s Devon Energy has been evolving re-fracturing techniques in the Barnett to slow the decline in base production through various methods.