This paper presents a method for pinpointing intervals for fracture stimulation in horizontal wells targeting unconventional oil plays. The observation of crossflow among fractures has been of great concern as this phenomenon affects the productivity of producing wells. The cause is related to the effectiveness of fracturing stages, which by itself depends on the rock lithology. We identified interaction among fractured intervals from diagnostic modeling of performance data that exhibited cross flows in the wellbore. On wells exhibiting the most prolonged duration of crossflow, we noted the disadvantages of equal space fracturing. We then used the drilling parameters from MWD data for individual wells and computed the d-exponent profiles and noted significant differences in rock brittleness as characterized by their d-exponent data. Out of the more than 60 wells studied, wells exhibiting minor changes in the d-exponent showed the least indications of cross flows from performance data while in wells with significant cross flows we see the nonuniformity of the d-exponent profile and the negative impact of equal space fracturing.
The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
Research and development drives success in shale plays throughout the world, enabling operators to deploy new drilling, completions, and production technologies to reach more reservoir area and extend the life of production wells. This work demonstrates the development, validation, and deployment of an extreme torque casing connection addressing technical challenges of tubulars in unconventionals.
Throughout the well lifetime, Oil Country Tubular Goods (OCTG) experience various loads during the installation, stimulation, and production phases. Some of the challenges experienced during the stimulation and production phases relate to internal and external pressure resistance, sealability, corrosion and cracking, erosion, and wear. Furthermore, with the increase in lateral length and the more demanding well geometries, the OCTG capabilities related to high cycle fatigue, connection runability, and torque limits become more important to safely and efficiently reach the total depth of the well and ensure integrity throughout well life. Another scenario in which the torque limit of an OCTG connection is important is rotating while cementing, a practice undertaken to mitigate sustained casing pressure, improve well integrity, and completion efficiency.
We present the key elements in the development of a casing connection that overcomes these challenges and the decision process leading to a prototype. To prove the design concept, a fit-for-purpose testing protocol was adopted to validate its performance, replicating the installation, stimulation, and production phases under the expected loads. Once validated, a pilot involving casing installation, rotation while cementing and stimulation was completed in two wells, and its outcomes will be discussed in this work.
This novel casing extreme torque connection, designed to overcome the application challenges, enables the installation of casing in longer laterals, together with the improvement of well integrity through rotation while cementing.
The performance of the product, tested through a special procedure while ensuring reliability, was confirmed by the case study from the Niobrara shale. A new connection considering the challenges of wells in unconventional plays must account for several aspects from design to installation. We show the process, from the design stage and validation, leading to successful field deployment.
Directional drilling for hydrocarbon exploration has been challenged to become more cost-effective and consistent with fast-growing drilling operations for both offshore and onshore production areas. Autonomous directional drilling provides a solution to these challenges by providing repeatable drilling decisions for accurate well placement, improved borehole quality, and flexibility to adapt smoothly to new technologies for drilling tools and sensors. This work proposes a model predictive control (MPC)-based approach for trajectory tracking in autonomous drilling. Given a well plan, bottomhole assembly (BHA) configuration, and operational drilling parameters, the optimal control problem is formulated to determine steering commands (i.e., tool face and steering ratio) necessary to achieve drilling objectives while satisfying operational constraints. The proposed control method was recently tested and validated during multiple field trials in various drilling basins on two-and three-dimensional (2D and 3D) well plans for both rotary steerable systems (RSS) and mud motors. Multiple curve sections were drilled successfully with automated steering decisions, generating smooth wellbores and maintaining proximity with the given well plan.
Ryan, M. (Baker Hughes, a GE Company) | Gohari, K. (Baker Hughes, a GE Company) | Bilic, J. (Baker Hughes, a GE Company) | Livescu, S. (Baker Hughes, a GE Company) | Lindsey, B. J. (Baker Hughes, a GE Company) | Johnson, A. (Murphy Oil Company) | Baird, J. (Murphy Oil Company)
Development of unconventional reservoirs in North America has increased significantly over the past decade. The increased activity in this space has provided significant data with respect to through-tubing drillouts which had previously not been attainable. This paper is focused on using the field data from the Montney and Duvernay formations along with laboratory data and numerical modeling to understand the hole cleanout associated with through-tubing drillouts of frac plugs.
Initially, an extensive full-scale flow loop laboratory testing program was conducted to obtain data on debris transportation for hole cleanout during through-tubing applications. The testing was conducted on various coiled tubing (CT)-production tubing configurations using various solid particles. The laboratory data was used to develop empirical correlations needed for a transient debris transport model. This model was then used for frac plug drillouts to ensure successful hole cleaning in actual field applications. Computational fluid dynamics (CFD) modelling was also used to further understand and quantify the differences between the laboratory data, field data and transient debris transport model results.
The objective of the work conducted was to gain a better understanding of debris transport and validate the empirical modelling approach developed for hole cleaning. The validation process was conducted in several stages. The first stage was to validate the laboratory data against the Montney and Duvernay field data. The second stage was to verify the results obtained from the empirical model against the results obtained from a computational fluid dynamic model. The results from both modelling approaches were lastly compared to the field data. All these results challenge the current industry's understanding and best practices for through-tubing drillouts in the Montney and Duvernay formations. With the contentious increase of lateral lengths and higher stage counts, the process of drilling out frac plugs has become more complex. This study explicitly benefits all operators in their ever-increasing need to understand their frac plug drillout operations to ensure efficient, cost effective, and most importantly, consistent and repeatable results.
While efficient results for frac plug drillout operations have been accomplished to date, the on-going feedback from the field has been the requirement to produce repeatable drillouts. This paper is the first to show a holistic approach for obtaining a transient debris transport model used for through-tubing drillouts of frac plugs. The novelty also consists of the transient debris transport model validation through laboratory data and actual Montney and Duvernay field data.
Implementation of a drift-flux (DF) multiphase flow model within a fully-coupled wellbore-reservoir simulator is nontrivial and must adhere to a number of strict requirements in order to ensure numerical robustness and convergence. The existing DF model that can meet these requirements is only fully posed for upward flow from 2 degrees (from the horizontal) to vertical. The work attempts to extend the current DF model to a unified and numerically robust model that is applicable to all well inclinations. In order to achieve this objective, some 5805 experimentally measured data points from 22 sources as well as 13440 data points from the OLGA-S library are utilized to parameterize a new DF model - one that makes use of the accepted upward flow DF model and a new formulation extending this to horizontal and downward flow. The proposed model is compared against 2 existing DF models (also applicable to all inclinations) and is shown to have better, or equivalent, performance. More significantly, the model is also shown to be numerically smooth, continuous and stable for co-current flow when implemented in a fully implicitly coupled wellbore-reservoir simulator.
Hansen, Mary (McDaniel & Associates Consultants) | Hamm, Brian (McDaniel & Associates Consultants) | Wynveen, Jared (McDaniel & Associates Consultants) | Schlosser, Tyler (McDaniel & Associates Consultants) | Jenkinson, David (McDaniel & Associates Consultants) | Dang, Hoang (McDaniel & Associates Consultants)
Unconventional reservoirs with low permeability shales and siltstones are currently being developed using horizontal wells in multiple layers. As this development technique has become more common, accurately understanding well-to-well communication is increasingly critical. Well positioning, reservoir thickness and well interference effects are important factors in the success of multi-layer development. Traditional well density metrics such as wells per section and lateral well spacing do not account for the multi-layer nature of these plays. This paper introduces readily derived metrics that enable a three-dimensional (3D) quantification of multi-layer well density.
Unlike traditional analysis which considers pad development from a bird’s eye view, this paper considers the vertical cross-section of a pad which enables the 3D drainage to be quantified. The metrics Cross-Sectional Drainage Area (XDA) and Three-Dimensional Proppant Intensity (3DPI) are defined. XDA quantifies the well density relative to the thickness of the reservoir. 3DPI represents completion intensity and reservoir stimulation relative to the cubic volume of gross rock attributed to the multi-layer development. Once introduced, these two metrics are correlated to well and pad level performance. Examples from the Montney Formation in Western Canada and the Bakken Formation in North Dakota, USA are studied in detail.
Ultimate hydrocarbon recovery factors, early time well performance and production profiles are analyzed and compared to the XDA and 3DPI metrics using visual analytics and multivariate machine learning models. In both the Montney and Bakken examples, XDA correlates with well performance and 3DPI correlates with pad hydrocarbon recovery factors.
While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE).
The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year.
Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment.
The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production.
Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production.
With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives.
It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas.
This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations.
Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.
Real-time downhole estimation of inclination and azimuth is desirable for improved wellbore quality, better management of the drilling process with regard to wellbore hydraulics and drilling dynamics, and is a prerequisite for advanced directional drilling services such as downhole azimuthal hold mode and surface-based automated trajectory control. However, reliable estimation of azimuth while drilling remains a challenging problem, particularly in certain orientations in harsh drilling environments. We present a detailed problem description and describe the approach used to develop a new algorithm to estimate azimuth while drilling, which offers significant improvements over existing algorithms. Such an algorithm will form the foundation for advanced drilling system automation services, such as automated trajectory drilling.
When a restriction or nonconformity presents itself in a well, quickly and reliably diagnosing the nature of the anomaly can save diagnostic runs and help prevent similar cases elsewhere, reducing nonproductive time and operating costs. Downhole X-ray diagnostics provide this understanding quickly and reliably under diverse well conditions that limit the effectiveness of other downhole diagnostic techniques. X-ray diagnostics produce real-time, quantitative two-dimensional images and three-dimensional reconstructions of downhole objects and obstructions with high precision. We demonstrate this with a case study in which X-ray diagnostics accurately identified and quantitatively characterized an obstruction due to liner deformation.