Torsional instability in a drilling system is a significant challenge that limits performance. In its extreme form, known as stick-slip, the drillstring stops and restarts, exposing its downhole equipment to extreme forces that can lead to failures, unintended trips, and escalated operation costs. Torsional instability can also trigger lateral dysfunctions and whirl, creating further risk of bit and bottomhole assembly (BHA) failure. The risk of torsional dysfunction is heightened in applications involving concentric reamers and long drillstring, high-angle wells.
The correlation of polycrystalline diamond compact (PDC) bits with torsional dysfunction is well known, and different approaches have been suggested to address the issue. The fixed depth of cut control (DOCC) approach, which is commonly used to address the issue, limits the PDC bit and formation engagement at a pre-determined ratio of rate of penetration (ROP) and drillstring RPM. However, this approach has an uncertain success rate when drilling conditions change. To address the challenge of torsional dysfunction while drilling a directional well with a 12¼-in. pilot bit and a 14½-in. concentric reamer, a self-adaptive DOCC technology was deployed in a deepwater well in the Gulf of Mexico (GOM). The self-adaptive DOCC technology automatically adjusts the depth of cut engagement threshold as drilling conditions change, eliminating the manual parameter adjustment required at surface to manage torsional dysfunction.
The application of self-adaptive drill bit technology in the target well yielded excellent results, and the section was completed with a single bit/BHA run. Ninety-eight percent of the interval was drilled with no torsional dysfunction. The drillstring whirl was negligible, and 99% of the interval was drilled without lateral vibration. Eliminating harmful dynamic dysfunction significantly enhanced drilling performance and increased the ROP by 57% over the best PDC offset run. The dull bit condition was very encouraging; the bit displayed very low wear and no undesired impact damage, showing the effectiveness of the technology.
This paper uses real-time drilling dynamics field data measured downhole and demonstrates the effectiveness of self-adaptive DOCC technology for drilling performance improvement in deepwater directional well where torsional dysfunction continues to remain a significant challenge and could be a performance limiter.
Pandey, Ajeet Kumar (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Kumar, Vishwa (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Bharsakle, Anuradha (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Vasudevan, K. (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Singh, Dhruvendra (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited)
Quantification of uncertainty in input parameters to build a robust 3D geological model is an integral and perhaps the most crucial requirement in high-risk exploration areas. This demands more innovative and effective management of uncertainties for optimizing reserve portfolios and better formulation of exploration and exploitation strategies for oil and gas fields. The present area of study pertains to Mumbai/Western Offshore Basin of India. The reservoirs of the study area are challenging due to their high spatio-temporal heterogeneity and discrete fluid distribution. Wells drilled during the field development plan are devoid of hydrocarbon from the lower zone of the reservoir (Middle Eocene/lower Bassein pay) while upper zone (Late Eocene/upper Bassein pay) produced significant amount of gas despite same lithological composition and structural setup, which reduced the utility of pressure-performance based or conventional modeling approach as it couldn't explain the complex geological set up of the deposition.
In this background, a thorough evaluation of critical aspect of most complex and anisotropic carbonate reservoir of Bassein Formation of Middle to Late Eocene age has been taken up to delineate the trends of favorable locales in the area. Inputs from micro-facies analysis, fluid transmissibility of Formations and diagenetic imprint analysis were considered to start the present study. An integrated methodology was designed incorporating seismic, well/logs, core samples, sedimentological, bio-stratigraphic & reservoir data to estimate petrophysical properties and necessary modifications in conventional approach were introduced for capturing the reservoir heterogeneity and stochasticity. Hi-frequency digenetic cycle mapping at log scale and pre-stack inversion results (P & S impedance, Vp/Vs ratio) were incorporated to build a robust geo cellular model and characterize the reservoir.
Uncertainty analysis presented in this study is mainly focused on structural and petrophysical parameters. The effect of each parameter/factor and their interaction effect (response) with other parameters are analyzed through Optimization Algorithms, to quantify the uncertainties and its impact on reservoir characterization. Sensitivity analysis indicated that Oil Initially In Place (OIIP) exhibits significant sensitivity to effective porosity and water saturation. Therefore, distribution pattern of these uncertainty parameters are derived from Probability Density Function (PDF) and used to restrict the variability of the volumetric estimates to retain the P10/P90 ratios within the acceptable ranges.
Quantification of structural parameter was performed using non-linear multiple regression technique, constrained by statistically Maximum Allowable Error (+Standard Deviation).
Present analysis enabled us to reduce the uncertainty associated with various reservoir characterization elements. Further, it enhanced robustness of velocity modeling, petrophysical and lithological interpretation through determination of uncertainties with high degree of accuracy and provided their role in estimation of final hydrocarbon-in-place volumes. The parameterization of the uncertainties deliberated could be used as a template in other fields sharing similar structural and depositional characteristics to mitigate the risks associated with Field Development Plan.
With known basement hydrocarbon accumulation, Mumbai High field in Western Offshore, India is a priority area for extending the concept of fracture characterization in metamorphic basement reservoirs. Basement in Mumbai High is hydrocarbon bearing in few areas proximal to major fault damage zones and intersections of major regional tectonic cross trends. The challenge lay in characterizing such basement reservoirs with significant heterogeneities in mineralofacies, in situ stress fields, seismic amplitudes, fracture properties and connectivity, and flow potential. This necessitated development of an integrated static fracture model workflow assimilating structural modeling, seismic and petro-physical interpretations for fracture drivers and geocellular fracture modeling, fine tuned using geological concepts and point data extracted from well data analyses. The deterministic geo-cellular fracture model thus prepared has been calibrated with real time well observations and has been found to satisfactorily explain anomalous hydrocarbon accumulation and flow pattern in basement wells tested in the area. The adopted workflow has helped planning wells for evaluating and exploiting basement reservoir as well for real time monitoring of wells.
Thapliyal, Anil (Oil and Natural Gas Corporation Ltd.) | Kundu, Sudeb (Oil and Natural Gas Corporation Ltd.) | Dimri, Sunil Kumar (Oil and Natural Gas Corporation Ltd.) | Dutt, Ankit (Schlumberger) | Mishra, Shubham (Schlumberger) | Aggarwal, Akshay (Schlumberger) | Agarwal, Ankit (Schlumberger) | Ojha, Aditya (Schlumberger) | Bradley, David (Schlumberger) | Giddins, Marie Ann (Schlumberger)
For planning the operations of Oil and Natural Gas Corporation Limited (ONGC) in the complex Heera field, it was estimated that over one hundred simulation runs would be needed to complete the history match of the field and almost the same number of simulations would be needed for production forecasting. Heera is a large field, with multiple faults and seven stacked carbonate formations. There are significant variations in petrophysical properties, and variable degrees of communication between reservoir zones. The simulation models include 479 wells with commingled production or injection. Well trajectories are complex and include multilateral and horizontal configurations. Field development options include use of simultaneous water alternating gas (SWAG) for enhanced oil recovery.
Combining all these features, it would be difficult to run all the necessary sensitivity cases within the required project timeline, using a conventional reservoir simulator. Therefore, it was decided to test the applicability of a new generation simulation tool to address the challenges of the study.
To ensure that the change of simulator would not impact the integrity of the model, rigorous quality checks were performed on the input data. After successful evaluation, the new software was used for the reservoir engineering study.
The decision to apply the new simulator significantly reduced the elapsed time, with some realizations over 20 times faster compared to the original base case. As a result of this speed-up, numerous runs could be carried out to refine the history match. Multiple sensitivities could be used to help understand and reduce the uncertainties in a more comprehensive manner. Moreover, the prediction cases could be optimized to identify the best recovery strategy.
This study has demonstrated the value of reducing simulation run times, to complete the project with greater efficiency and more confidence in the results. In future studies, high performance software tools can also enable use of fine resolution models, to capture detailed heterogeneities and optimize areal and vertical sweep.
Verma, Chandresh (Baker Hughes Integrated Operations) | Rodriguez, Fernando (Baker Hughes Integrated Operations) | Qasin, Qazi Mohammed (Baker Hughes Integrated Operations) | Chaaouri, Aramco Mohsen (Baker Hughes Integrated Operations) | Akel, Sami (Baker Hughes Integrated Operations) | Akiki, Ghassan (Baker Hughes Integrated Operations) | Afolabi, Jonathan (Baker Hughes Integrated Operations)
Energy consumption and demand are steadily increasing. Hydrocarbons have been an important energy provider for several decades, but production from mature oil and gas producers is declining. Great effort is put into improving oil and gas reservoir recovery to meet this rise in energy demand.
In the subject reservoir where the pay zone is a thick, multi-layered limestone, characterized by low-permeability; conventional techniques yield lower than expected production results.
To improve production and the ultimate recovery of the field, extended-reach drilling (ERD) wells with long horizontal multilaterals (Quad and Penta-laterals well types) were drilled to attain maximum reservoir contact (MRC), ranging from 10 to 14 Km. These wells equipped with intelligent completions, enable uniform contribution along the extended horizontal intervals. This contribution is achieved through better flow management of the different sections of reservoir contact, reducing operational drawdown pressures, and delaying gas and water breakthrough. The result is high well potentials, improved long-term performance of sweep and recovery, and increasing net worth of the drilling investment.
This paper presents the lessons learned from hundreds of ERD multilateral wells drilled in the field, including integrated operations, progressive approaches and innovative applications, improved drilling practices on a continuous basis, and the tools and techniques used to drill and complete the wells safely and efficiently.
These efforts achieved a milestone record rate of penetration (ROP) in the Middle East of 5,000 feet per day, and as a direct result contributed to minimizing well delivery time by 35 % and average 25% reduction in well cost in an always challenging drilling environment.
The design approach, job execution and evaluation of drilling performance are presented in this paper; as well as key technical challenges and risks encountered during planning and execution stages and how these were mitigated and overcome for MRC improvement and optimization.
Well construction was challenged to meet the complex multi-lateral with long cantilever sections.
The MRC optimization schemes applied in the field resulted in dramatically reduced days of drilling operations that led to millions of dollars in project savings and the achievement of world class drilling records.
Chowdhury, Ashabikash Roy (Baker Hughes Inc.) | Callais, Ryckman (Baker Hughes Inc.) | Rodrigue, Wayne (Baker Hughes Inc.) | Alferez, Carlos H (Baker Hughes Inc.) | Anderson, Mark (Chevron U.S.A. Inc.) | Terziev, Ivaylo (Chevron U.S.A. Inc.) | Angeles, Magdiel (Chevron U.S.A. Inc.)
The operator is active in drilling deepwater (DW) exploratory, appraisal, and development wells in the central and western areas of the Gulf of Mexico (GOM) where water depths exceed 4,000 ft. In this demanding application, a key step to a successful well is achieving high performance in the large-diameter surface sections of the well. This important segment can start a well ahead of the authorization for expenditure (AFE) or create setbacks and added unplanned costs. Increasing the rate of penetration (ROP) and improving wellbore quality are two essential components for reducing cost of the riserless sections of any deepwater well.
Verticality must be maintained throughout the 26-in. large-diameter section to reduce casing wear and to ensure torque and drag remains minimal while drilling to deeper depths. The 26-in. hole section is drilled riserless and a high ROP generate additional savings by lowering the drilling fluid cost. The higher percentage of cuttings provides the additional equivalent mud weight so pump and dump (PAD) mud is not required. The increased ROP needs to be achieved with low vibration levels to avoid any bottom hole assembly (BHA) component failure that would necessitate an avoidable and costly round trip.
The operator has previously drilled with 18⅛-in. hybrid bits in salt and sub-salt formations and has recognized the potential of hybrid bits and their ability to drill fast with stable drilling conditions. Several drilling records have been set in this hole size. Encouraged by the performance gains and better drilling efficiency of initial hybrid bit runs, the operator planned to reduce cost of their riserless drilling section in a batch drilling program in GOM.
The 26-in. hybrid bit was implemented to batch drill three hole sections, each approximately 3,400 feet long. The operator was able to optimize the drilling parameters for each successive well due to growing confidence in the stable drilling environment. This enabled the drillers to increase the ROP and greatly improve time savings. The three intervals were drilled at ROP of 255, 308, and 379 ft./hr., respectively; breaking GOM field ROP records for each consecutive run with this operator. All three penetration rates have also surpassed the current world record ROP for this hole size. Subsequent 26-in. hybrid bit runs have established consistently higher ROP and have proven to be a significantly better solution when compared to polycrystalline diamond compact (PDC) bits.
This paper presents the details of the performance improvements achieved through the use of large-diameter hybrid bits, compares the drilling efficiency of large-diameter PDC and hybrid bits, and discusses some important design aspects of the hybrid bit that deliver stability and steerability.
Panna field is located in the western offshore region of India and produces oil and gas from Middle Eocene and Early Oligocene Bassein limestone. Production is taken mostly through 3 ½" or 4 ½" tubing through a packer set in 7″ liner. The Panna-Mukta-Tapti Joint Venture (PMT JV) took up a plan to revive wells addressing well integrity issues and limitations associated with old completion jewelry for increasing the production.
Work-over campaign was planned for four wells on PB and three wells on PC platform to enhance production. The plan was to cut and retrieve the old completion and tubing above the 7″ permanent packer and install improved completion, having facilities of Permanent Down Hole Gauges (PDHG), Gas Lift Mandrel (GLM) and Chemical Injection Mandrel (CIM) through an additional packer set in 9-5/8″ casing.
In line with two barrier philosophy, two plugs were set inside the production tubing, one at TRSSV (shallow-set) and another one below the production packer (deep-set). The plug below the production packer doubled-up to also hold back the workover fluid, which may have hampered the productivity of an already sub-hydrostatic reservoir, if losses occurred. However, at the end of workover operations, the retrieval of this deep set plug could not be done even after various attempts and spending valuable rig time. This problem was faced with three out of the first four wells, which proved to be a challenge and forced the team to devise a new strategy for remaining wells.
At this point, an ingenious solution was devised to employ Plasma Based Punctures (PBP) to puncture the tubing in the limited space between the packer and the deep set plug to kick back the wells into production. Rig based PBP operations were carried out on two PC wells and Rig less PBP operations were carried out on three PB wells to get them online post work over operation. This resulted in saving several hours of rig time as the deep set plugs could not be retrieved in the conventional planned slick line operations.
This paper intends to highlight the challenges faced, and how PBP proved to be the optimum solution, by simplifying operations and ensuring the timely delivery of production.
The PBP operations proved viable through savings on energy, resources, time and cost associated with work-over jobs. The potential savings were roughly 780,000 bbls of oil which were significant for the aging asset. It is therefore, a potent alternative to other costly solutions in a scenario that often fails to deliver objectives, as happened in this campaign.
This paper discusses two high-temperature-resistant polymers (Polymers A and B) that have been developed as thermally stable, dual-functional viscosifiers and fluid-loss additives. Polymer A was designed for monovalent brines, while Polymer B works for divalent brines. These polymers enable the formulation of brine-based drill-in fluids that are stable at high to ultra-high temperatures, which is a significant improvement when compared to conventional biopolymer-based drill-in fluids. When combined, the two polymers work synergistically to further reduce fluid loss in monovalent brines.
The two thermally stable polymers were readily incorporated into various drill-in fluid formulations containing either monovalent or divalent brines over a broad range of densities. These drill-in fluids exhibited exceptional thermal stability and showed no stratification after static aging at 400°F for three days or at 375°F for seven days. A minimal change in fluid behavior was observed when comparing the rheological properties of the un-aged and aged samples. The samples provided excellent fluid-loss control, even after aging. A synergistic effect was observed between Polymers A and B when used in monovalent brines to further reduce the HPHT fluid loss with no negative impact on fluid rheology. Core flow tests showed that both fluids were non-damaging after acid-breaker treatment. It is anticipated that these polymers will extend the envelope to which water-based drill-in fluids can be successfully used to drill high- and ultra-high-temperature reservoirs. Recent successful field trial of the divalent brine-based fluid as a testing fluid further proved the robustness of these fluids for these reservoirs.
Bit designers use the well-established practice of placing depth-of-cut (DOC) control features at strategic heights from the cutter profile to selectively manage drill bit aggressiveness and to maximize drilling performance. But, until now, the elements used for depth-of-cut-control were a fixed part of the bit. An innovative new feature enables compact element replacement and/or adjustments at the rig site using a mechanical locking design. The driller can quickly adjust the bit responsiveness before each run, if wanted, to optimize performance factors such as rate of penetration and tool face control. This paper describes the benefits, ease of use, positive results and reliability of this new technology with examples from multiple applications for a variety of bit designs.
The final design was selected and validated based on a number of evaluation methods including concept screening tests, simulated laboratory drilling tests and field tests. The initial screening tests evaluated the ease of compact installation and removal for various concepts using a test block. Full bit testing using a full-scale, high-pressure, downhole drilling laboratory evaluated installation, integrity and aggressiveness response changes using compact height adjustments. Finally, multiple field tests on wells in North American applications of the Eagle Ford, Marcellus, and DJ basin formations provided data to refine the mechanical design and improve manufacturing processes to achieve a robust technology.
Field tests proved the new design to be highly reliable, with drilling performance that matched or exceeded the performance of bits with standard brazed compacts in the same fields. This new design provided the unique ability to rapidly optimize bit responses. This paper describes the technical lessons learned, guidelines for use and tools developed to maximize the benefit from this innovative new feature.
This new method enables compact element installation and removal within fifteen minutes on the rig site for the purpose of repair or aggressiveness modification. In contrast, traditional methods of DOC control include long lead times to alter bit design, manufacturing and delivery. Drillers can reap the immediate benefits of improved bit performance by changing bit design on the rig site using direct feedback of bit aggressiveness and steerability between runs without needing multiple bits on site. Ultimately, this new bit technology provides improved drilling performance and greater efficiency for the operator.