With the advent of the development of lower Tertiary formations in the deepwater Gulf of Mexico, a gap in proppant technology was identified at the beginning of the decade. No existing conventional proppant could provide the required conductivity at the anticipated 15,000 psi (and higher) prevailing closure stress. To meet these challenges a new proppant was developed, with the goal of achieving twice the baseline conductivity of any conventional proppant at 20,000 psi.
Improvements in the manufacturing process lead to the required superior performance needed in extreme depth and stress environments. The shape of the new Ultra-High Stress Proppant (UHSP) is highly round and spherical with a mono-sized sieve distribution. At higher stresses, this means the UHSP will provide higher proppant pack porosity and ultimately more space to flow. In addition, the surface of the proppant is very smooth, leading to lower Beta, as well as reduced erosion potential. An extremely low internal pellet porosity evenly distributed in fine pores results in much stronger grains, with crush value of less than 2% at 20,000 psi for 20/40 mesh equivalent product. Additionally, the new proppant technology provides further advantages with increased durability and longevity, as well as significantly reduced erosion on downhole tools and equipment.
Further to the ultra-high stress applications the new manufacturing technique was applied to ores typically used to manufacture low density ceramics. The result is a proppant with equal or better conductivity than standard intermediate and high density ceramics leading to larger frac volume and better carrying capacity. This new low density ceramic can effectively replace the use of conventional ceramics from low to medium and high stress applications and in many cases reduce the costs associated with pumping these higher density proppants.
This paper will briefly review the manufacturing process and resulting step change advancements achieved by this new proppant, stressing on the technology adoption in the Gulf of Mexico illustrated with multiple case histories. This paper should be beneficial to all engineers and technologists currently working in fracturing applications from low to ultra-high stress, or other harsh conditions such as steam-flooding and geothermal applications.
Two Schlumberger companies, Cameron and M-I SWACO, joined efforts to provide market with a drilling fluid optimization system to be used during drilling operations. Cameron delivers a complete remote-controlled and automatic drilling fluids mixing system, while M-I SWACO's technology facilitates continuous real-time measurement, analysis and optimization of mud properties. Today mud samples are measured every 6 hours or more frequently, depending on the conditions in the well. The properties are then adjusted for the most part manually, based on a mud engineer's practice.
The Cameron Automix system comprises mechanized equipment and a robot for addition of chemicals into the drilling fluid, and works in concert with the M-I SWACO RheoProfiler instrument, which measures and analyzes drilling fluid properties in real time. Schlumberger (SLB) algorithms, designed to care for the known wellbore situations, automatically create optimal recipes for the chemicals to be mixed into the drilling fluid.
The synergies between M-I SWACO's core competence in fluids and RheoProfiler technology and Cameron's competence in software and mixing equipment, result in a unique method / system of continuous stabilization and control of the wellbore through drilling fluid optimization.
With the focus on a fully autonomous ‘closed-loop’ drilling rig, the spotlight is strongly directed on the drill floor activities and their automation. The main goal of SLB, in terms of automation and closed-loop activities, is to improve the primary well barrier, keep well conditions under control, and rig safe. A combination of each company's strengths, Automix and RheoProfiler can play an essential part in moving the drilling industry towards the same philosophy of fully automated and intelligent systems. The entire drilling operation needs to be viewed as one system, with one organization working towards a common goal, reducing exploration cost without compromising safety. However, there will always be a need for the mud engineer on board.
Less visible in the general hype around automation and more efficient drilling operations, is the importance of optimized properties of the mud in the drilling process. Safety during drilling, better well bore, economy or producing reservoir are just a few of the benefits of the SLB solution.
Meza, O. Grijalva (Institute of Petroleum Engineering, Clausthal University of Technology) | Kamp, K. (Institute of Petroleum Engineering, Clausthal University of Technology) | Asgharzadeh, A. (Institute of Petroleum Engineering, Clausthal University of Technology) | Bello, O. (Institute of Petroleum Engineering, Clausthal University of Technology) | Freifer, R. (Institute of Petroleum Engineering, Clausthal University of Technology) | Oppelt, J. (Institute of Petroleum Engineering, Clausthal University of Technology)
The technique of drilling a wellbore by using casing instead of drill pipe (Casing Drilling-CD) is gaining in relevance within the Oil & Gas sector since its implementation in the last decades. This technique, aside from the evident reduction in drilling time and costs observed whenn applied is convenient to minder the effects of certain while-drilling issues as those arising while drilling unstable formations. The focus of concern in this work will be the geometry-related aspects of Casing Drilling influencing not only the drilling operation itself but its particular well control needs as well; this latter will be explained in detail.
Accurate numerical modeling of surge and swab pressures in concentric annuli is proposed. The numerical scheme is developed for the laminar flow occurring during the drillstring axial movement. The model incorporates Yield Power Law (YPL) fluids, which is a good representation of the most of the drilling fluids. A commercial computational fluid dynamics (CFD) package is used to validate the developed numerical model. Also, the mathematical model and CFD analysis are compared with the existing models from literature.
A high order finite difference numerical model is developed that accurately captures the physics of laminar flow due to surge and swab phenomena in concentric annuli. The numerical scheme is prepared such that it accounts for both Newtonian and non-Newtonian fluids. YPL model is incorporated in the proposed scheme, and it accurately estimates the drilling fluid behavior in both high and low shear rates. CFD analysis is conducted using a commercial software to validate the accuracy of in house developed numerical model. The velocity profiles across the annulus are compared in order to verify the precision of the model.
The proposed model for the surge and swab pressures is more accurate than narrow slot approximation model which is most commonly used in the drilling industry. With this proposed modeling, the physics of surge and swab pressures are better captured, because it accounts for the effect of curvature in annular geometries. The model is well-validated with the CFD analysis and the velocity profile comparison of the numerical solution and CFD analysis yields less than 5% average absolute percent error. With this work, dimensionless velocity profiles are presented which better explain the flow during surge and swab in concentric annuli, while the inner pipe is reciprocating in steady-state.
Pulling out or running tubulars in the vertical section, or running casing with centralizers approximates the position of tubular to concentric. It is very important to accurately calculate these pressure losses to avoid fracturing the formation or having an influx from the formation. Therefore, CFD analysis and mathematical modeling of surge and swab pressures presented in this study has potential to optimize the tripping operations that will help avoid hole problems.
Continuous development of drilling technology has enabled the oil and gas industry to drill deeper and more complex well paths. Drilling dynamics measurements have been the dominant contributor to rate of penetration maximization, overall drilling optimization and downhole assembly reliability assurance for more than three decades.
A consequence of today's complex downhole assemblies and well paths are higher downhole forces and vibrations. These conditions require more quality drilling dynamics information than before for safe and efficient drilling. Driven by this demand, new developments in downhole and surface equipment have made available larger amounts of drilling dynamics data with higher sample rates. In parallel, development of reliable high-speed telemetry allows the high-resolution drilling dynamics data to be utilized on surface to deliver answers while drilling. These developments were made possible due to the recent advent of high-performance downhole-capable electronic technologies, as well as the availability of increased computation power for signal processing at the rig site.
This paper describes improvements in the drilling dynamics measurement systems to overcome the challenges imposed by deeper and more complex wells. Gathering, processing and transmitting drilling dynamics data at high rates introduces challenges due to tighter downhole sensor requirements, the required digital signal processing power, amount of available memory, electronics temperature tolerances and telemetry requirements. Optimized hardware design, signal processing and enhanced telemetry sequences and methods are answers to these challenges, to ensure the adequate performance of drilling dynamics measurement systems. These improvements allow a fast response to new drilling conditions, the adjustment of drilling parameters to changes in formation, and a rapid evaluation of drilling performance. This enables field personnel to make decisions focused on drilling optimization, and these case histories are added to advance drilling optimization best practices.
The drilling dynamics measurement system described in this paper has been successfully run in challenging fields in the North Sea and Middle East. Compared with offset runs, the system has significantly increased data quality and sample rate and provided, in addition to industry-standard-measurements, unique measurements for the identification and mitigation of high-frequency torsional oscillations. Examples of the improved capability and operational performance are provided.
This paper also highlights changes necessary to further improve drilling dynamics measurement systems for evolving real-time drilling optimization needs.
Why the world drilling limit envelope shows an irregular triangle as a whole and how to break its limitations? Many scholars have carried on the related researches, the authors also give theoretical reason, including the influence of borehole space, bearing capacity of drilled formation, mechanical factors and hydraulic factors. In this paper, the authors provide the effects of drill pipe tripping in/out and casing running on the world drilling limit envelope. Meanwhile, the drilling extended-reach limit optimization model is also established, its parameters include objective and subjective factors. The objective factors mainly refer to the formation factor; and subjective factors mainly include three types of parameters: drilling constraint parameters, wellbore design parameters and specific operating conditions. The subjective factors in the drilling extended-reach limit optimization model is mainly divided into the following three situations: the variation of drilling constraint parameters, the variation of wellbore design parameters, the drilling constraint parameters and the wellbore design parameters change simultaneously. In addition, the horizontal extended-reach well (ERW) is the well type which most frequently breaking world drilling record in recent years, and also the well type most likely to break the drilling world record in the future. Moreover, the concept of effective extended-reach limit is proposed. The borehole trajectory design is optimized using genetic algorithm, reducing the well's extension in non-reservoir formation and improving the effective extended-reach limit, so as to break the world drilling limit envelope. This work provides a practical tool for explaining why the world drilling limit envelope shows an irregular triangle and how to break the envelope's limitations, which is of great significance for the development of drilling engineering and improvement of economic benefits.
Alimuddin, Sultan (M-I SWACO, A Schlumberger Company) | Sharma, Sunil (M-I SWACO, A Schlumberger Company) | Mahadeshwar, Sachin (M-I SWACO, A Schlumberger Company) | Marinescu, Pavel (M-I SWACO, A Schlumberger Company) | Raman, Chakrapani Venkat (M-I SWACO, A Schlumberger Company) | Kumar, Yogesh (M-I SWACO, A Schlumberger Company) | Velavaraj, Nirmaladevi K (M-I SWACO, A Schlumberger Company) | Panicker, Santosh (M-I SWACO, A Schlumberger Company) | Rahim, Syed Abdul (Schlumberger)
To maximize oil and gas production, it is paramount to reach the whole reservoir and extract hydrocarbon resources efficiently. Moreover, to reduce the costs in today's market, the well should be drilled in minimum operating time with no operational failures. This paper presents a detailed study and outline of a neoteric practice of using a wellbore strengthening while drilling, to drill a depleted deepwater reservoir and eliminate nonproductive time related to downhole losses. This novel solution has the potential to be used while drilling depleted reservoir sections in all Middle East areas.
In a deepwater block situated on India's east coast, synthetic-based reservoir drilling fluids are used to drill the reservoir section. While drilling depleted reservoir sands, dynamic losses amounting to 300 bbl/hr were encountered that led to nonproductive time and even abandonment of well. To continue the drilling campaign and lessen the downhole losses, fracture sizes of depleted reservoir sands were simulated using proprietary software. Considering the measurement-while-drilling (MWD) tool's limitations and other reservoir behavior, a reservoir drilling fluid with wellbore strengthening material was formulated. Extensive laboratory tests were conducted to confirm the bridge and sealing capability of the solution. Subsequent to laboratory testing, the same reservoir drilling fluid formulation was field trialed. The well was drilled successfully with no hindrance, except minor losses encountered at the top of the sand. Implementing this customized solution, combined with precise running strategy, led to effective results in more than four wells to date.
This paper presents a comprehensive study of drilling depleted zones using wellbore strengthening while drilling, identifying ideal products, studying reservoir compatibility, calculating cost effectiveness, evaluating overall performance based results, and overcoming challenges while implementing the strategy in deepwater wells. A detailed comparison of all the challenges that occurred while drilling and the proper troubleshooting steps are also discussed. Finally, the paper aims to compare the existing results with previous drilling techniques, which may help operators with the future development of respective fields. In this application, new technology of reservoir-friendly, loss prevention materials of ultra large size were used successfully.
Sandstone matrix acidizing is a challenge in most cases. The conventional mud acid system involving hydrochloric acid and hydrofluoric acid (HCl:HF) is widely used in stimulating sandstone formations. The disadvantage of using HCl:HF is in its rapid reaction rate, resulting in insoluble by-products from secondary and tertiary reactions that limit the treatment effectiveness. The system can also limit the acid's performance capability when deep formation stimulation is targeted.
Enhancing HCL:HF acid system has been developed by utilizing of a protective ion-complexing agent. The agent forms a temporary protective film on clay surfaces allowing the acid to react with the remaining parts of the formation. The stimulation treatment fluids can be placed within the open hole reservoir section using two methods. The first utilizes 2-in. by 1-in. concentric coil tubing (CCT) with side-jetting nozzles to achieve uniform placement across the horizontal section and deep penetration inside the matrix. The second method uses a conventional bull heading treatment.
Laboratory testing was performed to qualify the treatment. Different minerals were used to evaluate and understand the retardation of different acid systems. The solubility of clays was lower comparing to normal HF acid systems, indicating the slow reaction of the acid on clays and a sign that improved retardation was achieved. Further testing confirmed the formation of a protective layer on clays, enabling the acid to react more efficiently with the remaining minerals. After successful laboratory testing, field trials were conducted on four oil-producing wells in southern Oman that experienced fines migration issues. The main acid system was squeezed into the matrix, followed by brine post flush, and then flowed back. Treatments with the protective acid systems in the treated wells showed a net oil gain of 30% to 80% sustained for longer than six months.
This paper outlines the technical challenges in the design and application of the proposed acid system and presents the successful lab results indicating the formation of the protective film on the clays minerals and the deep penetration phenomenon.
De-completing wells — due to downhole problems related to tubing-casing annulus communication, casing leaks or prior to executing re-entry sidetracks for multilateral wells — is adaily activity in the oilfield business. Conventional completions comprised of downhole production packers and tubing are normally retrieved with no major issues. But this is not the case for intelligent completions, as they include a numberof downhole components that makes its retrieval more challenging, and there was no set procedure or provision in place to retrieve them, in case of failure or encountered downhole problems during the production life of the well.
Since intelligent completion deployments are increasing, the number of intelligent wells to be de-completed will also increase.
This paper presents the case history and experience gained during the de-completion of intelligent completions of different designs; highlights the challenges and difficulties in recovering of multiple packers and flow control valves; and the strategy to achieve full access to the wellbore, to re-establish production and recover assets. This paper will also summarize lessons to achieve successful de-completion of an intelligent well.
Srivastava, Manish (ADNOC Offshore) | Ali, Abeer A. Al (ADNOC Offshore) | Alshehhi, Ali S. (ADNOC Offshore) | Kumar, Amit (ADNOC Offshore) | Spuskanyuk, Oleksandr (ADNOC Offshore) | Abdulhai, Walid M. (ADNOC Offshore) | Gan, Chee Lam (ADNOC Offshore)
Annuli pressure if not controlled and managed may result in uncontrolled release of high-pressure hydrocarbon fluids from reservoir to the surface. This may cause loss of life, damage to environment, and tarnish the reputation of the company. In this paper, two potential pathways for reservoir fluid to reach the surface through annuli have been examined, and recommendations were provided to diagnose and manage annulus pressures within safe operating limits.
Integrated well integrity assessment to diagnose the root-cause of annulus pressure involved using various tools to measure key parameters needed to make an accurate assessment of root-cause of annulus pressure. For example, thermal numerical models and lab tests were conducted to simulate thermal effects in the well and analyze annulus fluid samples, respectively. Furthermore, echometer was used to measure fluid-level in the annuli, whereas logging tools such as spectral noise, high-precision temperature etc. were used to identify source of any reservoir fluid ingress.
Multiple diagnostic, surveillance and management workflows for outer and inner annuli have been developed. Experiences in implementing these workflows for hundreds of wells in the field have been described and lessons learned have been discussed. Special attention has been paid to the cases with confirmed or suspected lost barriers. Appropriate, cost-efficient levels of diagnostics have been selected and employed to ensure safe operations. Decision trees on how to manage wells with annulus pressures have been discussed, in particular related to planning and execution of pressure bleed-offs, annulus top-ups with heavier fluids, etc. Based on decision trees, cost-efficient levels of diagnostics have been selected and employed to ensure safe operations.
This work provides insights on various tools to diagnose and cost-effectively manage the pressure in the annulus by combining the available tools and software. Company-specific annulus pressure management strategies have been developed and successfully employed to safely operate wells with annulus pressure.