The development of unconventional resource plays in the United States has led to numerous changes in the fields of drilling engineering and reservoir evaluation. During the initial years of high commodity prices, the act of drilling a horizontal shale well became more of a service and less of a science in an effort to increase speed of development. Reservoir evaluation through logging suites and core analysis was cast as an unnecessary cost and shale reservoirs were deemed to be "statistical plays"
This new "lower for longer" pricing environment has spurred ingenuity in an effort to elevate non-core acreage to core acreage status and enhance well productivity. Operators have shifted their views on reservoir evaluation by running logging while drilling (LWD) tools behind the bit, logging through the bit on wiper trips, or cased-hole logs such as a pulsed neutron and dipole sonic. Of interest in this paper is the use of drilling data as an analog for conventional logging suites, which add time, cost, and risk to well operations. By applying mechanical specific energy (MSE) data generated from the penetration of the formation, drilling engineers can turn an often disregarded data set into both cost savings and enhanced well productivity.
Saini, G. (The University of Texas at Austin) | Chan, H. (The University of Texas at Austin) | Ashok, P. (The University of Texas at Austin) | van Oort, E. (The University of Texas at Austin) | Isbell, M. R. (Hess Corporation)
Substantial volumes of data are collected during modern drilling operations. However, the business value of such data is limited unless it can be analyzed quickly to derive practical knowledge for application on subsequent wells. The sheer quantity and messiness of data can overwhelm oilfield personnel, making it difficult for them to extract value. An automated process is necessary to extract knowledge quickly and efficiently from large datasets. Our team identified a preliminary set of 12 questions with answers that provide immediate knowledge to help improve the drilling of subsequent wells. Each of these ten questions is best answered through a storyboarding process. The process involves the automatic creation of a series of one-page visuals with just the right amount of information on each page to validate the answers to the questions. Standardizing the structure of the data (well-site data, survey data, geology data, well plans, etc.) enables software to rapidly create these visuals and is an important step in the process.
This work describes how the storyboarding process was applied to a dataset of more than 100 gigabytes (GB) from 16 shale wells drilled in North America. Examples of questions that could be quickly answered using the process are: ‘What was the best drilled well on the pad?’ and ‘Did a particular bottom hole assembly (BHA) improve drilling in a particular section of the well?’ Scripts were written in Matlab and Python to automatically process the raw data and generate more than 20 different types of one-page visuals that are well suited to present the answers to such questions. The illustrated information includes insights into BHA performance, wellbore tortuosity and quality, vibrations, weight on bit transfer, and other drilling dynamics. Identifying the relevant KPIs to satisfactorily answer the questions and present exactly the right information from the vast amounts of data was a challenge. This paper documents and describes the concept of storyboarding that uses visuals to answer comprehensive questions. This concept is not yet widely applied in the drilling industry today, but is expected to be quickly adopted by stakeholders interested in drilling performance improvement and cost saving opportunities.
This paper focuses on anti-collision best practices developed and implemented by Liberty Resources for horizontal drilling across pre-existing horizontal wellbores within the same horizon in the Williston Basin. These multidisciplinary collaborative workflows have allowed Liberty Resources to successfully drill multiple complex horizontal wellbores traversing as close as 10 feet wellbore-to-wellbore to existing laterals.
As the horizontal infill development of unconventional reservoirs progresses, complex wellbore trajectories with heightened collision concerns will be required. To achieve this requires advancing the industry's anti-collision standard practices with new and more precise anti-collision methods, detailed planning, and near perfect execution. In the Williston Basin alone there are over 13,000 vertical wells, 15,000 horizontal wells, and over 1,000 re-entry and directional wells drilled to date, with the first horizontal wells introduced to the basin over 30 years ago. Historically, the horizontal wells were drilled using a vast array of well designs and orientations due to the limitations of technology, industry practices and standards, and the insufficient understanding of the reservoir. Advancements in drilling and completions technologies and a better understanding of the reservoir now allow leases to be reassessed for infill potential. This increased infill development has led to increasingly complex wellbore trajectories with collision concerns not only for existing vertical wellbores but now also for existing horizontal wellbores within the same or proximal horizons.
The anti-collision best practices include directional and geologic planning considerations, operational tolerances and requirements including zonal determination, communication protocols, and risk management practices. Creating a broad framework that allows for flexibility to adjust for distinct operational constraints.
These workflows and tolerances have been implemented in three horizontal wellbores traversing seven same-formation pre-existing horizontal wellbores. The anti-collision method was successfully applied in both the Middle Bakken and Three Forks formations, each with their own varied and unique geologic characteristics, demonstrating applicability for a wide range of reservoirs. The ability to execute complex wellbores opens new opportunities to access additional resources in previously considered "fully developed" acreage.
The methods presented in this paper have allowed the routine drilling of horizontal laterals as close as 10 feet to existing laterals. This technology can be applied to a variety of reservoirs opening new opportunities to access additional resources previously considered unrecoverable due to existing wellbores.
Ball sealers are commonly applied in fracturing and acidizing treatments for diverting treatment fluid to the desired zones by plugging perforations. It has proven that injecting ball sealers is a low-cost and efficient method for diversion. To predict the effectiveness of ball sealers, an improved ball sealer seating model is developed by introducing the maximum seating efficiency and random functions to capture the stochastic nature of ball-sealer plugging. The new model can predict ball sealer performance with different ball densities in vertical, deviated and horizontal wells.
The traditional ball sealer model was originally designed for vertical wells, where ball sealers with different densities have similar behavior. However, for deviated and horizontal wells, the seating of buoyant and dense balls is more complicated. Buoyant balls tend to plug the perforations at the top of wellbore, and dense balls tend to plug the perforations at the bottom of wellbore. Thus, the traditional ball sealer model cannot be applied in these wells. A maximum seating efficiency for each ball is introduced in the new model, which is obtained by correlations based on experimental results. To describe the stochastic nature of ball sealer seating on perforations, a random number is assigned to each ball sealer, and a range is assigned to each perforation based on the ratio between flow rates through the perforations and flow rate in the wellbore.
With the improved model, it can predict seating efficiency of ball sealers for all types of well with buoyant, neutral and dense balls. The results are showing that the seating efficiency of ball sealers predicted by the model can match the experimental results, which validates the model. Based on the simulation results, when ball sealers with mixed densities are pumped into deviated or horizontal wells, the seating efficiency is better than pumping ball sealers with only one density. For vertical wells, the benefit of mixing densities is minimal.
Numerous studies on unconventional shale well production data have shown that downhole pressure fluctuations can exceed 300 psig during a slugging period. Such pressure fluctuation will result in very high drawdown and could lead to near-wellbore formation damage when the rock failure criterion was met. An engineering workflow was developed to investigate the impact of multiphase slugging events on cemented casing plug and perforation (CCPP)and open hole sliding sleeves (OHSS) completions. Based on transient pressure analysis and geomechanical evaluation, safety operational envelope was generated to minimize the risk of formation damage due to slugging behavior.
In this study, a dynamic multiphase flow simulator was used to predict the pressure amplitude and frequency during the slugging events in both a CCPP and OHSS completion configuration. The results from the simulation were then incorporated into a geomechanical model to analyze and identify potential hydraulic fracture closure and formation damage concerns, which can compromise well performance.
The results from this study show that OHSS completion is more vulnerable to damage during the downhole slugging period than a CCPP completion. However, severe formation and fracture damage could occur during downhole slugging for CCPP well if the well is operated outside the safety operational envelope. Results from the two case studies led to the conclusion that it is crucial to consider the effect of downhole slugging on near-wellbore fracture and formation integrity to avoid permanent and irreversible damage.
It was recently shown that anisotropic wormhole networks may arise from the acidizing of anisotropic carbonates. In openhole or cased and densely perforated completions, where in isotropic formations the wormhole network would be expected to be radial around the well, the actual stimulated region may be elliptical in anisotropic formations. Analogously, in completions where the limited entry technique is used, the wormhole network is expected to be spherical in isotropic formations, but it may actually be ellipsoidal in anisotropic formations. That has an impact on the well performance and should be taken into account when designing the acidizing treatment and the completion. At the same time, the use of a limited entry technique may result in better stimulation coverage and also longer wormholes, but it may also result in a partial completion skin factor, impairing the productivity from the stimulated well. This should be taken into account when estimating the stimulated well productivity.
In this study two main topics are analyzed: the impact of wormhole network anisotropy and the impact of a limited entry completion. Both radial and spherical wormhole propagation patterns are considered, to be applied in both openhole and limited entry completions. The differences in well performance is studied for each case, and analytical equations for the skin factor resulting from each scenario are presented.
The anisotropic wormhole networks are obtained from numerical simulations using the averaged continuum model, and the results are validated with experimental data. The analysis of the well performance is made through simulation of the flow in the reservoir with the different stimulated regions.
The results show that for highly anisotropic formations the wormhole network anisotropy may have a great impact on the acidized well performance and this should be taken into account in the acidizing treatment design. It was observed that the anisotropic wormhole networks present lower productivity than equally sized isotropic stimulated regions. Hence, equations like Hawkins formula should not be used for estimating the skin factor from anisotropic wormhole networks, and the equations proposed in this work should be used instead.
Specifically, the impact of anisotropic wormhole networks is large when the limited entry technique is used. It is shown that for this type of completion there is an optimum stimulation coverage of about 60 to 70%, and the perforation density required to obtain for a given acid volume depends strongly on the wormholes' anisotropy. The skin factor equations proposed in this work for the stimulation with limited entry completion should be used for obtaining the optimum perforation density for a given scenario.
Guo, Boyun (University of Louisiana at Lafayette) | Li, J. (University of Petroleum China Beijing) | Cai, Xiao (University of Louisiana at Lafayette) | Zhang, Xiaohui (University of Louisiana at Lafayette) | Wang, Gui (Southwest Petroleum University)
Lost circulation is commonly recognized as one of major drilling complications that cause low efficiency and a high cost in oil or gas well drilling. The current practice of mitigating lost circulation with lost circulation materials (LCM) is still empirical due to the lack of understanding of near-wellbore conditions. This work the first time uses pressure transient data analysis method to infer the near-wellbore conditions in lost circulation wells. The fluid level survey data can be converted to bottomhole pressure
A good knowledge of foam hydraulics and cuttings transport (hole cleaning) is essential for successful applications of foam drilling technology in horizontal wells. Estimating local fluid velocity in a partially blocked eccentric annulus (due to cuttings) is a challenge; so, a new analytical method of calculating local stress and velocity (near cuttings-bed in annulus) in an eccentric annular flow is derived which makes it possible to estimate the bed height for foam drilling in horizontal wells. Therefore, a new equation for local velocity (critical velocity) to initiate particle movement is used in order to predict the bed-height profile in a build-up or horizontal section of wellbore. This investigation also focuses on understanding the effects of drilling parameters on bed height and cuttings concentration.
A new transient wellbore hydraulics and cuttings transport model has been developed using the finite difference method of continuity equations for foam and cuttings. In order to predict the cuttings bed formation in horizontal wells, a mechanistic hole-cleaning model consisting of two layers has been utilized. The model is based on torque balance for a particle on the surface of a bed. In addition, a new model has been formulated for the local shear stress by modeling the eccentric annular flow as the infinite number of concentric annuli with variable outer radius. Similarly, using the narrow slot-approximation technique, a local velocity profile has been determined analytically in the eccentric annulus to be applied in the torque balance equations. Subsequently, model predictions of bed height were compared with published experimental data and the model is fine-tuned to minimize discrepancies.
Results show the cuttings bed front transitions through the annulus along the build-up and horizontal sections. Model predictions showed a good match with experimental results for concentric horizontal annulus except at higher polymer concentrations (greater than 0.25%). The simulation results show that bed height and cuttings concentration are quite sensitive to the changes in surface foam injection rates and back-pressure, thereby can be best optimized by properly adjusting these input parameters. The results also suggest that hole-cleaning is a function of inclination. The bed height increases with increase in inclination angle until a critical angle of 90°-φ (φ is the angle of repose) after which, it reduces.
This paper describes a new approach to evaluating the effectiveness of the rotary steerable system (RSS) steering mechanism on wellbore tortuosity in horizontal wells. Wellbore tortuosity in drilling applications is defined as any unwanted deviation from the planned well trajectory. As reservoir objectives become more complex and exact, operators increasingly perceive the wellbore tortuosity as a serious concern in the process of drilling, completing, and producing wells.
More than 700 wells were reviewed and analyzed in this study. Strict criteria were set during the classification process; the studied wells have a common geology and trajectory, and they use a very similar bottomhole assembly (BHA) design. The inclination values from the wireline tool are used to illustrate the attainable benefits in terms of wellbore quality and measure wellbore tortuosity. In addition, the wireline inclination data are compared with the actual measurement-while-drilling (MWD) survey to highlight the existence of the micro-dogleg severity (DLS) that cannot be measured by standard surveys.
Due to the theoretical differences in the steering mechanism between the various types of RSS, it has been claimed that utilizing one steering mechanism over another can produce a less-tortuous wellbore. These steering mechanisms have previously been classified as either push-the-bit or point-the-bit mechanisms. The relative merits of a push-the-bit steering mechanism vs. a point-the-bit steering mechanism is an over-simplification; neither mechanism can deliver the premium wellbore quality the industry demands from RSS. The present study introduces the continuous proportional steering method (CPSM), and demonstrates how this mechanism can provide superior wellbore quality by reducing wellbore tortuosity. In addition, a superior inclination hold performance is observed in horizontal sections drilled with the CPSM. Curve intervals are more continuous and smoothly drilled through the planned directional changes.
The research becomes a useful reference to analyze the performance and efficiency of RSS steering mechanisms across drilling and workover operations. Directional drilling service companies are encouraged and challenged to improve the efficiency and accuracy of RSS mechanisms, improving the hole quality and reducing micro-doglegs.
Khemissa, Hocine (ADNOC offshore) | Channa, Zohaib (ADNOC offshore) | Nofal, Salman F. (ADNOC offshore) | McNeilly, Kevin Dean (ADNOC offshore) | AL-Felasi, Ali (ADNOC offshore) | Al-Mazrooqi, Laila Sayed (ADNOC offshore) | Al Qubaisi, Salama Darwish (ADNOC offshore) | Al-Shamsi, Latifa Ali (ADNOC offshore)
The company vision development plan to capitalize on oil production, sustainability, maximise recovery and as cost effective to reduce number of wells to be drilled requests to drill extended horizontal drains (Oil producer and water Injector).
Subsurface well location optimisation, focus in detail on targets location and the related risks. The present offshore case study, demonstrate furthermore how important to study in detail all hazards along the well path, such as lithology of side-track formation. The risk of well bore stability, collapse is very high in such formation. Subsequently, in case of collapse or drop of scratched portion of rocks, the horizontal drain will be plugged and cease to produce. This case study, demonstrate how this event happens and adequate solution was successfully applied.
To efficiently perform the proposed plan, and develop multilayer geological units with poor to moderate limestone, a detailed reservoir study was performed including all subsurface team and drilling division. It was proposed to drill and complete wells as extended horizontal drain (+3000 ft.), with several designs: multilateral drains or step down 6″open hole.
The first planned well was dual oil producer, two targets, one deviated and the second 6 inch horizontal 3000 ft. length. Feasibility with drilling engineer was performed to study all drilling parameters, drilling hazards, logging requirement, geosteering, equipment preparation and simulation for acid stimulation was showing easy to be executed with barge.