This study describes the concept of Liquid-Assisted Gas-Lift (LAGL). This concept includes three main parts: two-phase downward flow in annulus, two-phase flow through orifice Gas-Lift Valves (GLVs), and upward two-phase flow in pipes. The latter part is well described in the literature and will not be investigated in this work. However, there is a lack of studies on two-phase downward flow in annulus and through GLVs. Therefore, these two topics are investigated in this work.
An experimental and numerical study on two-phase flow through orifice GLVs is presented. The experimental results are compared to predictions using a numerical model published in the literature for two-phase flow through restrictions. It is observed that the mechanistic model could successfully characterize two-phase flow thorough gas-lift valves with errors lower than 10%. A flow regime map of downward two-phase flow in the annulus is used to analyze the flow regimes observed during field-scale experiments of LAGL unloading. It was concluded that the intermittent and bubbly flow are preferred to minimize injection pressure during LAGL unloading operations.
A commercial flow simulator is used to perform sensitivity analysis of the LAGL system and to perform unloading of a well using the LAGL concept. The unloading simulation results indicated that the use of LAGL has the potential to decrease the injection pressure requirement in more than 50% when compared to the conventional single-point gas injection. The simulation model is shown to be a useful tool to perform system analysis and optimization of LAGL.
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.
Traditional gas-lift technology blossomed between 1929 and 1945, with about 25000 patents being issued during this time
The concept of High Pressure Gas-lift (herein after referred to as HPGL), as discussed in SPE 14347
The case for eliminating failure-prone gas-lift valves is self-evident. However, the case for the second application will be proffered. Conventional gas-lift, while recognized as excellent for producing high volumes of solids- laden fluid from deviated wells, underperforms ESP's in new horizontal oil wells due to frictional losses associated with high tubing flowrates. The case will be made that SPGL combined with reverse flow mitigates the frictional losses associated with high flowrates. Similar to a coil tubing cleanout using high pressure nitrogen, high pressure natural gas can lift large volumes of fluid without the need for gas-lift valves.
Technology and products for HPGL currently exist. Multiple compressor designs will be summarized to show that only one additional stage of compression is needed to support HPGL, with three and four stage designs being capable of performing the task. The recommendation will be made that HPGL compressors be assembled from readily available components, and that multiple pilot tests be made by industry. The importance of maintaining temperatures through the compression process high enough to prevent hydrocarbon condensation will also be explained.
This paper discusses case histories with solutions-oriented approach to shale gas cementation problems. Shale gas exploration and production around the globe in general, and US in particular has witnessed surge in activity to the extent that Shale gas is often regarded as ‘a game changer’ in the hydrocarbon industry. The success in United States has prompted the governments of several countries to develop their own shale gas programmes.
In India, estimates of shale gas resources vary from 63 Trillion Cubic Feet by Energy Information Administration (US). In order to tap this resource, Government of India came out with a Shale Gas and Oil Policy in 2013. Consequently, ONGC and OIL were given blocks mainly in Gujarat to test shale production technology and potential.
ONGC drilled 1st shale gas well # JMSGA of Jambusar field and well # GNSGA of Gandhar field, Cambay basin successfully. But CBL - VDL shown very poor results. After this failures, two more shale gas wells were awarded to service provider to carry out cementation for GNSGC and GNSGB wherein the cement slurries were used by adding proprietary chemicals. Results shown some improvement in CBL-VDL against shale gas.
Poor CBL-VDL creates a problem in production operation both for geothermal wells and oil wells. To accomplish good cement bond, complete removal of mud /all well fluid is necessary to enhance the displacement efficiency by maintaining desired rheological properties. However, in spite of this, many times the cement bond leading to poor bonding/ insufficient zonal isolation.
As a part of strategic planning it was decided to develop in house innovative expertise to solve the problems. Accordingly an extensive experimental analysis were carried out specially using expanding additives (3-5% bwow) in cement system, exhibited improved properties like Right Angle Set, Compressive strength, Stability, fluid loss control and desired rheology. Practically, combinations of salts in cements and spacers in pre flushes in cementing fluids have provided means for managing shale instability. Learning experience from past utmost care was taken for optimization of rheological hierarchy for mud, spacer and cement using fluid friction chart and cement software shown a phenomenon improvements in achieving desired parameters.
The field trials have been carried out successfully in three shale wells in India. 1st Well # TVAU of Cauvery and recorded excellent CBL-VDL (1-2 mV) against shale gas. 2nd Well # WDAU of Ahmedabad. Achieved excellent slurry/spacer parameters.3rd Well # ROBB of Agartala for 5-1/2" casing cementation resulted in better CBL-VDL (02-07mV) against shale zones.
These innovative techniques are cost effective, easy to handle and technically suitable. Also establishes in-house technological advancement in designing cement slurries and become a proven approach for cementing Shale gas wells in near future.