Shrivastava, Pranay (Cairn India Limited) | Sharma, Vedant (Cairn India Limited) | Anand, Saurabh (Cairn India Limited) | Otubaga, Ademola (Cairn India Limited) | Trivedi, Ranjan (Cairn India Limited) | Muda, Mazlan (Cairn India Limited) | Parasher, Arunabh (Cairn India Limited) | Tiwari, Shobhit (Cairn India Limited) | Aihevba, Leste (Cairn India Limited)
This paper will describe how good project management and communications between the various project stake holders resulted in the successful completion of the Raageshwari 15 wells fracturing campaign. The 93 fracturing stages were completed under budget and in a shorter time frame than planned. The management of the project included multiple and diverse operations and equipment including perforating, wireline, well testing, hydraulic fracturing, HSE, and waste water management.
The Raageshwari deep gas field (RDG) is a deep, tight, high condensate gas reservoir located in Rajasthan, India. The 15 wells were located on 3 separate pads within 2 km radius. Their location, in a sparsely populated arid part of India adds to the logistical challenges. Some of the key challenges during the project were: Key operations such as fracturing and perforating cannot be performed at night. Economic handling and disposal of waste water. Continuous supply of water suitable for fracturing and other wellsite operations. Limited space available on the well pads. Requirement for simultaneous operations involving high risk activities such as perforating and high pressure pumping. High CT cleanout frequency due to the requirement of underflushing the frac stages, close proximity of the adjacent stages, and the small volume in the 3 ½ inch monobore completions. Logistics and supply chain management in a remote location.
Key operations such as fracturing and perforating cannot be performed at night.
Economic handling and disposal of waste water.
Continuous supply of water suitable for fracturing and other wellsite operations.
Limited space available on the well pads.
Requirement for simultaneous operations involving high risk activities such as perforating and high pressure pumping.
High CT cleanout frequency due to the requirement of underflushing the frac stages, close proximity of the adjacent stages, and the small volume in the 3 ½ inch monobore completions.
Logistics and supply chain management in a remote location.
Solutions for these obstacles included improved procedures, workflows and key technology introductions. These included: Simultaneous rig up to multiple wells. Simultaneous operations covered through Risk assessment and controls in place. Selective perforation technology to reduce perforating time. Mechanical evaporators and a robust CSR team for waste water management.
Simultaneous rig up to multiple wells.
Simultaneous operations covered through Risk assessment and controls in place.
Selective perforation technology to reduce perforating time.
Mechanical evaporators and a robust CSR team for waste water management.
The various optimizations resulted in a reduction in days per frac stage from 4 in the previous campaigns to 2 in this campaign. The project was delivered with 0 LTI (Lost Time Injuries), and a phenomenal HSE record due to robust safety procedures, frequent audits, safety drills etc.
This paper will detail how the challenges in this project were overcome resulting allowing a high speed fracturing campaign to be successfully executed in a remote location.
This paper provides the design and operating considerations for Progressive Cavity Pumping (PCP) systems in Coal Bed Methane (CBM) wells based on field experience and illustrates their optimization with case studies of C-Fer software simulation and field trial. The challenge is to effectively lift water throughout the CBM well life with the same PCP system while accommodating pressure head increments and flow rate decrements with time. This paper presents a novel idea to optimize PCP system at different stages of CBM well life with minimal cost implications to the company.
The major inputs for artificial lift design are seam depth and well productivity, while PCP head and flow rate, down-hole string sizing and motor sizing are the required outputs. To take a case study of PCP system optimization, we have Well – A, where the bottom perforation is at 600 m and the water production is expected to start with a peak of 150 m3/day at 100 m water level and reach 100 m3/day at 600 m water level in about 10 months. The authors chose a system with flow capacity of 76 CMD at 100 RPM and lift capacity greater than 800 m. Tubing size of 2.875″ is chosen and sucker rod size of 1″ is chosen. The surface motor of 22 kW is selected based on the maximum power required by the PCP system at the maximum lift condition. The process of selection is depicted clearly in this paper.
Although, the PCP system is designed as per the design considerations, the maximum RPM in the initial CBM well life may be limited by the pulley ratio (driven pulley diameter: driving pulley diameter) while the torque imparting capability of the motor at later stages may be limited by the motor frequency at the later stages of the well life. Hence, simulations for different run scenarios (water levels and flow rates) were done in C-Fer PC-Pump software for two cases taking Pulley Ratio as 4.74 and 6.22. The authors have presented trends comparing important parameters namely Fluid Level-Surface Motor loading, Fluid Level-Maximum Rod Torque and Fluid Flow Rate-Pump Speed. Based on the interpretation of these results, it was decided to experiment with two different driving pulleys for changing the pulley ratio during the well life to optimize the PCP system instead of upsizing the motor. This field trial was successfully conducted in Well – B and the parameters and the results are clearly depicted in the paper. Changing the pulley ratio over CBM well life will fulfill the torque and power requirements at the required pump RPM with significant cost savings by eliminating the need to install a new motor.
Gupta, Abhishek (Cairn India) | Sharma, Vedant (Cairn India) | Parasher, Arunabh (Cairn India) | Thummar, Dinesh (Cairn India) | Satyarthi, Rajesh S. (Cairn India) | Rao, Eshwar (Cairn India) | Tiwari, Shobhit (Cairn India)
Drilling, Completion and Well Intervention operations generate waste water. With the increasing volume of well fluids being flowed back due to aggressive Well Intervention activities, there was a need to handle and dispose the waste water efficiently. This was required to maintain continuity of well flow back and stimulation operations in an efficient and sustainable manner without incurring additional cost keeping in mind the current Oil and Gas market scenario.
This paper presents the "Best out of Waste" methodology adopted by the Well Services Department of Cairn India Limited to manage the huge waste water volumes by pooling in-house resources for developing Waste Water Treatment Project.
This project as it stands today was brought together by first, evaluating various treatment methods such as EC (Electro Coagulation) unit, Chemical methods, Particle settling and Disposal methods such as natural evaporation, evaporators (Mechanical and Solar) and injection and further combining features of the above stated methods to gain maximum benefit. These evaluations led to selection of EC Unit combined with the effectiveness of Mechanical evaporators and Natural evaporation for decreasing the waste water footprint.
Second, identifying a disposal well for treated water injection, established by various integrity and injectivity tests to confirm that the well was ready to accept the water with parameters and properties similar to that of EC unit output. The encouraging results in the injectivity tests proved to be the kick-off point of the project. Continuous monitoring of the treated water was also done to ensure the TSS and oil in water remained within the acceptable limits for injection, as per prevailing norms.
Third, developing disposal pits and tank farm to facilitate the treatment and dumping of the treated waste water. Lastly, decreasing current waste water inventory along with reducing the OPEX involved with handling, transportation and disposal of the waste water.
The key feature of this project was the utilization of above mentioned equipment's from internal resources of the company, which were either working stand-alone or were nonfunctional. Thus, the CAPEX for the project was brought to a bare minimum.
The objective of this paper is to present the various technical, administrative and commercial aspects associated with this project and conclude with plans of further utilizing the treated water for future Fracturing, Stimulation and even completion jobs.
Radhakrishnan, Venkataramanan (Schlumberger) | Bujnoch, John. (KrisEnergy Gulf of Thailand Ltd.) | Meteerawat, A. (KrisEnergy Gulf of Thailand Ltd.) | Wannaduriyapan, P. (KrisEnergy Gulf of Thailand Ltd.) | Abbasgholipour, Ali (Schlumberger) | Onkvisit, Sirikanya (Schlumberger)
The Wassana field is challenging in terms of formation. Past experiences with offset wells in the field confirmed that drilling below 5,000-ft (1524-m) true vertical depth (TVD) is challenging due to the formation becoming harder and more interbedded, resulting in premature failure of conventional polycrystalline diamond compact (PDC) bit designs. Several bit designs were tested, but most of the cutting structures were damaged when drilling below 5,000-ft (1524-m) TVD. The best strategy to optimize drilling performance in the Wassana field is to identify a suitable bit design with a durable cutting structure, which can drill beyond 5,000 ft (1524 m).
To meet the operator's goals, the service company proposed drilling the section with a new-technology bit that uses conical diamond elements (CDEs) on the bit blade with a rotary steerable system. The goals were to achieve the directional objectives in the shallow interval and successfully drill beyond the harder interval (8,000 ft TVD) down to TD. The rock strength of the formation ranges from 12,000 to 15,000 psi.
The PDC bit has CDEs with an ultrathick synthetic diamond layer, which provides extra durability for drilling at higher rate of penetration (ROP). This bit can withstand more weight on bit compared with conventional PDC bits of the same size, resulting in additional mechanical energy to penetrate the formation more efficiently. The CDEs protect the PDC bit by making it more stable, resulting in better tool face control. The 8½-in. directional section was successfully drilled to 11,200-ft 3414-m MD, which was the longest interval in the field. The strategically placed CDEs on the bit blades in conjunction with conventional PDC cutters not only increased the point loading but also enabled smoother torque control, leading to better steerability and durability. None of the offset wells achieved the feat of drilling more than 7,500 ft (2,286 m). The bit achieved the operator's goal of drilling 9,690ft [2954-m] and 10,043-ft [3061-m] MD. This result not only saved a trip but enabled the operator to gain confidence in redesigning the well profile with a greater measured depth. The operator accepted the fact that the bits with CDEs are more durable and also able to achieve the directional profiles better than conventional PDC bits. As a result, the operator changed the drilling strategy to drill longer intervals in the 8½-in. section. This strategy will increase drilling efficiency and lower the drilling risk of planning for more trips. The subsequent wells were planned using the same bit with CDEs to minimize the number of runs.
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.
Choudhary, Manish (Shell Technology Center) | Nair, Saritha (Shell Technology Center) | Pal, Sabysachi (Shell Technology Center) | Munimandha, Amuktha (Shell Technology Center) | Kohli, Abhinandan (Shell Technology Center) | Nirmohi, Samiksha (Shell Technology Center) | Gupta, Shyam (Shell Technology Center) | Jain, Sid (Shell Technology Center)
Integrated analysis of data together with fit-for-purpose modelling can help in fast track maturation of opportunities. In 2012, an opportunity to increase oil by implementing waterflood was identified, and last year was further reviewed by Shell. An integrated approach helped the team to mature ten development wells within three months which were subsequently drilled and helped the operator to surpass their production targets.
The field located in Western Desert, Egypt comprises of an Upper Cretaceous tidal channel system across four key reservoirs where sand thickness ranges between 2-15 m. Large uncertainties in reservoir extent, architecture and properties required the integration of data across multiple disciplines for identifying new development wells.
It was recognized early on that the construction of full-field fine-scale static models would be time-consuming and hence a simplified fast-track approach was used for maturing the opportunity. Conceptual depositional models were built by integrating dipmeter data, image logs and core facies descriptions to understand the direction of continuity of tidal channels, tidal bars and mud flats.
Net sand thickness maps were then constructed to represent the conceptual depositional model and integrated with the production behaviour of the wells. Production from historical wells drilled up to 2012 caused non-uniform pressure depletion across reservoirs. The pressure data from Modular Dynamic Tester (MDT), along with the production-injection history, was reviewed to identity both areal and vertical stratigraphically connected areas which were incorporated in the net sand maps. The constructed maps were quality checked with pressure and production data so as to validate the range of in-place volumes. Net sand maps, porosity maps and saturation models were combined to generate Hydrocarbon Pore Volume (HCPV) maps used to identify new well opportunities.
Separate sector models were also constructed to evaluate the waterflood and to optimise the decision parameters like injector-producer spacing, injection rates, voidage replacement ratio and target reservoir pressure. A range of type curves were generated from Monte Carlo simulation runs for all key sub-surface uncertainties then was used to estimate the low, base and high case recoverable volumes for the identified well locations and patterns.
The identified wells were drilled between February and August 2015 and helped increase production rates of the field by over 5,000 stb/d.A fit-for-purpose modelling using sand maps and connectivity maps can often greatly help in fast-tracking opportunity maturation and fine-scale detailed simulation modelling may not provide additional value.
Singh, Parvinder (Oil and Natural Gas Corporation Limited) | Sinha, M. P. (Oil and Natural Gas Corporation Limited) | Lal, Kishori (Oil and Natural Gas Corporation Limited) | Malhotra, S. K. (Oil and Natural Gas Corporation Limited) | Kumar, Pramod (Oil and Natural Gas Corporation Limited)
In this paper we present stress modeling and mechanical response of set cement sheath in cased wellbore to quantify induced stresses and design of suitable elastic cement system. Many cement systems with latex, Graphite & fiber material have been tested for mechanical properties (Compressive strength, Tensile strength, Poison's ratio and Young's Modulus) and results are evaluated by stress calculations. Stress model calculation matches with previous paper results in this line. Cement mixing is done as per API RP10B2 and cured in molds at 115°C for 72 hours under 3000 psi. Compressive strength was measured on UCS testing machine. Brazillian method has been adopted for evaluating tensile strength of set cement. Sonic wave velocity method used for evaluation of Poison ratio and Young's modulus. Loss of cement bond behind casing due to variation in wellbore pressure during Hydro-Fracturing and casing integrity testing has been observed in several wells. Stresses induced in the cement sheath due to variation of wellbore pressure are the cause of this damage. It has been observed that cement sheath being weaker in tensile strength, often fails due to tensile stresses. Results show that tensile strength is near about 1/10th of compressive strength in Portland cement which supports previous studies in this field. However this ratio is not fixed for all kind of cement system. Stresses developed in set cement system has been calculated by feeding mechanical properties in stress modeling. Based on induced stresses, a safe limit of pressure variation has been determined for many cement system. Hence out of many cement design, suitable cement design can be chosen for a particular wellbore condition. However prediction of wellbore pressure during Hydro-Fracturing and casing integrity testing is necessary in this case. The outcomes indicate that the elastic properties (Poison's Ratio and Young's Modulus) of the casing, cement, and formation play a significant role. Results show that for high pressure variation, cement system with better elastic properties are preferred over compressive strength. Stress calculation methodology helps to optimize the cement system to withstand high pressure during testing and Hydro-fracturing of well. Many cement system with improved elastic properties are tabulated and can be utilized in as per the suitability of wellbore condition.
Goyal, Rajat (Cairn India Limited) | Tiwari, Shobhit (Cairn India Limited) | Tibbles, Raymond Joseph (Cairn India Limited) | Anand, Saurabh (Cairn India Limited) | Ranjan, Vishal (Cairn India Limited) | Sidharth, Punj (Cairn India Limited) | Pathak, Shashank (Cairn India Limited) | Sharma, Anurag (Cairn India Limited) | Vijay, Utkash (Cairn India Limited) | Manish, Kumar (Cairn India Limited)
The Raageshwari Deep Gas Field in the western India, operated by Cairn India Limited, is a tight gas laminated reservoir (~0.1mD) with gross pay of ~700metres having numerous but small packets of good porosities and high gas saturations.
This paper describes the holistic approach used to cover the maximum net pay of the laminated volcanic rock using the limited entry technique of fracturing with limited number of frac stages. It also summarizes how the conventional temperature logging practice post injection tests helped cover the net pay, improve and verify the limited entry technique, decide the number of frac stages and calibrate frac model. Brief discussion also includes the results of production logging used to access the reservoir response to stimulation.
The fracturing jobs were conducted through 3-1/2″ Monobore completion with target depths at ~3400m TVDSS. The challenge in developing a multilayered thick tight volcanic gas reservoir using the conventional single interval per stage perforating is that it would require more than 10 independent stages to effectively cover the available net pay which was deemed to be uneconomic.
Limited entry Technique was used to combine number of sand packages in a single frac stage with high potential sands selected based on the reservoir and completion quality. Though fracturing simulators indicated theoretically that all of the perforation clusters which had different stresses and petro-physical properties, received pad and slurry to create a productive fracture, but verification was required.
The effectiveness of the diversion was verified using a combination of Step rate/Step down tests, post mini frac/frac temperature surveys, post treatment pressure matching and time lapsed production logging.
Limited Entry Technique has proved to be a cost effective method of increasing net pay coverage and EUR per well with minimum number of frac stages. Post SRT/mini frac/frac temperature surveys proved to be a very reliable, efficient and cost effective method for determining which perforations were taking fluid and the fracture heights which were generated. The heights obtained from the temperature surveys along with the pressure data/DFITs, were used to calibrate the hydraulic fracturing simulator. Also the production logging is showing the contribution form the all the targeted sands.
The application of limited entry technique, its verification using conventional temperature surveys and production loggings and the various operational and engineering learning acquired during planning to execution phase is an innovative and integrated approach in itself to exploit multilayered deep gas volcanic reservoir. Also pumping schedule modification like conducting step rate/down test in the pad sage or multiple step down tests in the same frac job were conducted while perforating individual interval/cluster
Lacustrine sediments of the Barmer Hill Formation are regionally spread throughout the northern part of the Barmer Basin, India. Laminated porcellanites of this formation are hydrocarbon reservoirs of commercial interest. The siliceous sediments were originally deposited as diatom frustules that underwent diagenetic transformation to Opal-A (diatomites) then to metastable Opal-CT (porcellanites) that finally stabilized as microcrystalline quartz. The mineral phase transitions are best characterized by trends in the rock physical properties.
Porcellanites are high porosity (~25p.u.), low permeability (~0.2mD) and moderate strength reservoir rocks. The diagenetic change from unconsolidated Opal-A silica to microcrystalline quartz occurs through a series of dissolution and re-precipitation processes impacting the petrophysical and mechanical properties of the rocks. Partially crystallized porcellanites have been regionally correlated in more than 500 wells within the basin. Porosity trends for these reservoir facies were analyzed in several shale content bins (Vshale windows), across the entire depth range. Necessary depth corrections were applied to offset the effect of basin uplift before comparing the compositional changes and trends of porcellanites across different fields.
Weathered porcellanites in Opal-CT form are seen in surface exposures. In the subsurface, multiple porosity-depth trends are observed in porcellanites that have undergone diagenesis and compaction, simultaneously. A prominent diagenetic trend (6p.u./100m) is observed at shallower depths indicating phase transition from Opal-CT to micro-crystalline quartz. The phase transformation reactions are catalyzed by temperature and detrital content of the rocks. At a greater depth, where most of the sediments are already converted to microcrystalline quartz, the compaction trend (2p.u./100m) dominates. This trend is comparable to the regional shale compaction trend. The porosity trends, especially in Opal-CT, are further complicated by the imprint of overburden compaction and the differential uplift of the basin. The transformation boundaries are not sharp and characterized by a transition zone where porcellanite porosities reduce from about~40p.u. to ~20p.u. The X-ray diffraction data indicate that the microcrystalline quartz grains tend to improve crystallinity within these transition zones. Diagenetic maturity increases from north to south in the Barmer basin with surface exposure of Opal-CT in the northern part and pure microcrystalline quartz in the deeper southern part of the basin.
Porosity-depth trend analysis gives a holistic overview of diagenetic phase transformation in the porcellanite reservoirs of the Barmer Hill formation. Electron Microscopy (SEM) and X-ray diffraction (XRD) data validate mineral phases at various depths in different parts of the basin. For an optimized field development planning of these reservoirs, porcellanites are best characterized by the property trends due to mineral phase transformations.
Raageshwari Deep Gas (RDG) is a clastic-volcanic reservoir located in the southern Barmer basin, India. RDG is a tight retrograde gas-condensate reservoir of permeability in the range of 0.01-1 md with a condensate gas ratio (CGR) of ~65 stb/mmscf. RDG is composed of a poorly sorted sandstone interval (Fatehgarh formation) overlying low net-to-gross (NTG) stacked succession of thick cycles of volcanic units (Basalt and Felsic) of ~700m gross thickness at a depth of 2800 m. RDG field is being developed using pad-drilled deviated wells, with multi-stage hydraulic fractures.
In tight gas fields, one of the major challenges is obtaining the right set of parameters to accurately forecast the estimated ultimate recovery (EUR) per well. EUR per well depends on fracture parameters such as fracture half-length (Xf), fracture height (Hf), fracture conductivity (Fc) and reservoir characteristics like matrix porosity (Φ), matrix permeability (k), net pay thickness (h), drainage area, reservoir pressure, reservoir fluid and operating conditions.
EUR may be estimated using decline curve analysis (DCA), rate transient analysis (RTA), and reservoir simulation. DCA is the simplest method but has high uncertainty early in a well’s production history, reservoir simulation is complex and requires detailed reservoir characterisation. RTA is easier compared to reservoir simulation and gives reasonable estimations of fracture and reservoir parameters. Since RTA is performance based it provides continuous evolution of high confidence EUR, even with limited production history.
To characterize tight fields, estimating kh of various layers through pressure transient analysis (PTA) requires long shut-in data. Thus PTA is generally only available for analysing early time effects (like fracture parameters). Thus, in low permeability reservoirs, RTA becomes preferred tool since it does not require shut-in data. RTA models and type curves generate non-unique solutions. Hence, integrating the petrophysical database with production logs, PTA results and RTA results is utilized to reduce uncertainty in k, h, Fc, and Xf. By utilizing all these data, the uncertainty in EUR estimation per well is reduced. These parameters are used as input for history matching to validate the interpretation and to optimize the RTA solutions. It was observed that history matches in RTA were improved when Fc and Xf from PTA were available. Flowing material balance (FMB) was then used to estimate drainage area, GIIP and EUR per well.
This paper demonstrates the workflow to use PTA, RTA, production logs, and petrophysical data to obtain the right set of parameters to get high confidence in EUR per well.
The finalized EUR per well for different well types can then be used for field development and deciding well spacing. Full field production forecasting based on RTA provides additional validation or an alternative to the estimates done through reservoir simulation.