With depressed oil markets and restrictions on project funding, and the sanctioning of developments, there is an acute focus on identifying areas where capital and operational expenditure can be reduced, maintaining capability and safety. One area of focus is on the conveyance method, namely the structure. With rig costs well construction and de-construction operations typically accounting for over 50% of the project cost base, it has been identified as an area where the introduction of new technology has the potential to significantly reduce overall project costs. The market adoption of alternative technologies, such as the "Rigless" approach is in its infancy in the Indian market, however regions such as the Gulf of Mexico and South East Asia have successful track record in the implementation of the technologies in completions, intervention and abandonment projects.
The paper describes alternative facilitating technology, focused on providing the required level of specification for the operations, with a reduction in the base cost of the technology, namely Rigless operations. The core technology is presented, with key facilitators. The application of the technology is presented in two case studies, each demonstrating the specific challenges of the operations and the novel solutions engineered to address these, and as such the significant potential benefits from a Rigless approach. The detailed and operational engineering presented in the case studies, and the identification of functionality requirements that can be improved to operate in technically challenging high cost projects, demonstrate the potential savings that can be achieved through the core technologies, and bespoke interfacing of them to client requirements.
Case study 1 presents a uniquely challenging abandonment campaign undertaken with a Supermajor in the Gulf of Mexico with a bespoke Rigless Unit. With the platform suffering hurricane damage and listing, bespoke technology was required to mobilize to the structure and safely isolate the hydrocarbon bearing reservoirs.
Case study 2 presents a large integrated well re-entry and abandonment campaign, with multiple partially abandoned and suspended wells. The integration of drilling equivalent circulating density techniques to the technology, present solutions that were devised to re-enter wells with annular communication and potentially underbalanced conditions. The flexibility of the Rigless Unit, and its ability to combine new technologies typically only available to integrate to drilling technologies, presents the value proposition of the Rigless Unit and approach.
Sinha, Pankaj (Cairn India Ltd) | Kumar, Varun (Cairn India Ltd) | Prabhakaran, Tushar (Cairn India Ltd) | Katre, Anurag (Cairn India Ltd) | Patel, Maulik (Cairn India Ltd) | Doodraj, Sunil (Cairn India Ltd)
This paper presents a more holistic approach to compare the drilling economics of Synthetic Oil Based Mud (SOBM or SBM) versus Water Based Mud (WBM) in onshore development drilling in India. Here, a key parameter which has been incorporated in the economics is the mud re-use and overall consumption trend of SBM versus WBM, which has been analyzed from statistical data across 200+ wells and quantified into overall cost savings with SBM estimated across roughly 500 development wells drilled.
The surface holes in all the development wells were drilled with WBM instead of SBM to avoid contamination of shallow water aquifers. Hence, the performance evaluation of SBM was limited to intermediate and production holes only, which were drilled with SBM. Also, past exploration and appraisal wells had used WBM for drilling these hole sections. A key parameter calculated from statistical data was average mud consumption (barrels per meter drilled) for SBM and WBM. The mud consumption of SBM and WBM is expected to differ because theoretically SBM can be re-used across greater number of wells compared to WBM. The average mud consumption was separately calculated for different hole sizes to better analyze the effect of hole size on mud consumption. The actual cost incurred with SBM application in development wells was calculated. Next, cost for drilling these wells with WBM was estimated using mud consumption (barrel per meter) data obtained from exploration/development wells. These two cost scenarios were compared to arrive at the net cost savings with SBM compared to WBM.
A maximum cost savings upto ~10 MMUSD (for various sensitivities especially SBM cost per barrel) is estimated across 500 wells in spite of the higher contracted costs of SBM (cost per barrel) when compared to WBM. The maximum cost saving of ~10 MMUSD corresponds to anticipated reduction in base oil cost in the current crude market. The savings with SBM are mainly attributed to the fact that SBM can be theoretically re-used infinitely moving from one well to the other while the WBM can be re-used for a limited number of wells. This cost model excludes any savings on part of SBM due to improved hole conditions and resultant reduction in drilling non-productive time.
SBM system minimizes drilling problems due to good clay inhibition, enhanced hole cleaning, lubricity additionally SBM is least effected by contamination. However, the higher cost per barrel of SBM and associated environmental concerns normally act as deterrents for operators to choose SBM for planning their wells. This paper provides clarity on the perception "SBM is costlier to WBM" and reinforces the recommendation to use SBM for drilling operations from an overall cost perspective.
Surfactant-Polymer (SP) flooding has been successfully used in some heavy oilfields in China. However, it still remains a challenge to extend the application of this method to more complex reservoirs especially considering the current low oil price, the high chemical cost and the complex reservoir conditions. So the paper studies the effect of liquid flow rate, SP injection mode, reservoir properties, well patterns and well spacing on the development performance of SP flooding, which can provide valuable guidance for economic design of SP flooding for various reservoir conditions under low oil price.
In order to evaluate the technical and economic suitability of the SP flooding, the ratio of enhanced oil production to equivalent chemical injection (EOPPC) is defined. In this paper, a basic reservoir model is established and history matched based on the pilot test in Shengli Oilfield. Then, a series of typical reservoir conditions are simulated by changing geological properties such as permeability heterogeneity and oil viscosity. Based on these reservoir models, the effect of liquid flow rate, SP injection mode, reservoir properties, well patterns and well spacing on SP flooding is studied. Besides, the relationships between optimum SP design and reservoir properties are discussed. Finally, a mathematical model characterizing the relationship between SP flooding performance, operational parameters and reservoir properties is established.
Results show that a lower SP flooding rate of 0.1PV/a and a higher post-SP water flooding rate of 0.2PV/a obtains the highest EOPPC of 44.73m3/t. As the permeability heterogeneity and oil viscosity increase, a lower concentration and larger slug size are preferred for better SP flooding performance when the total amount of chemicals is kept unchanged. Streamline analysis indicates injection and production well pairs should be located perpendicular with high permeable channels in order to increase sweep efficiency. In this paper, the line drive and five-spot well patterns obtain a higher sweep efficiency of over 82%. Considering the cost of well drilling and surface facilities, the economic well spacing is 140m between each pair of injector and producer. The developed quantitative prediction model has a fitting precision of over 98% and it is capable of assisting economic design of SP flooding for various reservoir conditions under low oil price.
The paper carries out studies on economic design of SP flooding according to particular reservoir properties. It also provides effective guidance for future pilot tests and commercial applications in more complex heavy oilfields under low oil price.
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.
Saraswati oil field is located in the central part of Barmer basin in Rajasthan, India. Primary reservoirs are within Barmer Hill Formation, deposited in a fluvial environment overlying the Fatehgarh formation. The Fatehgarh formation also includes sediments deposited in a fluvial environment, but there are also episodes of volcanic flows which were deposited in between the fluvial deposits. Volcanic flows in the upper part of the Fatehgarh mask the seismic reflections of the overlying basal Barmer Hill (BH) deposits. In this paper, we describe the methodology of effective integration of spectral decomposition attributes and seismic attributes to establish sand fairways of the Barmer Hill formation. The main objective of this study was to characterize the thin channel sands within the BH formation. Spectral decomposition technique was applied for characterizing thin bed reservoirs of the Upper BH section.. A combination of spectral decomposition and seismic attribute studies were conducted to distinguish and delineate the Lower BH sands from underlying Fatehgarh volcanics. The results from both these seismic studies were integrated with well and reservoir data to establish lateral distribution of sand fairways and their morphologies within the BH formation.
Libing, Fu (Research Institute of Petroleum Exploration & Development, CNPC) | Zifei, Fan (Research Institute of Petroleum Exploration & Development, CNPC) | Qingying, Hou (China University of Geosciences) | Jun, Ni (Research Institute of Petroleum Exploration & Development, CNPC) | Lun, Zhao (Research Institute of Petroleum Exploration & Development, CNPC)
The effect of bottom-hole pressure and formation pressure due to a partially penetrating well (PPW) is different from that for an open hole well. In order to analyze the effect of imperfection on pressure response type curves, this paper presents a 3D symmetry porous flow model for circularly partially penetrating wells. Laplace transform and Fourier transform and Bessel functions are applied to obtain the analytical solution of the model. The pressure response and pressure distribution are obtained and the influence on flow regime surrounding the well and pressure response caused by partial penetration are analyzed. Research results show that when the imperfect area tends to zero, the solution of the model can be reduced to the traditional model of the perfect wells presented by Theis, demonstrating the correctness of the solution. The early-time pressure is significantly lower than the case of complete well. The pressure difference between a partially penetrating well and a completely penetrating well decreases with time increasing. Without considering the variation of spatial distribution of flow field due to imperfect well it may bring about errors of formation parameters calculated by perfect well model. Those conclusions improve the seepage model and provide theoretical guidance for the transient pressure data interpretation, formation parameters calculation and productivity prediction of partially penetrating wells. The presented research content furthers the theory of well test analysis, and builds theoretical foundation for the technologies of well testing interpretation and reservoir numerical simulation.
In an unconventional reservoir, a thorough understanding of the spatial distribution of the physical properties of rocks, in terms of facies, porosity, and permeability, is essential for realistic dynamic reservoir simulation and history matching. This paper provides a practical solution for enhanced reservoir performance analysis, combining the results of geological interpretation, 3D geostatistical electrofacies modeling, and flow simulation in an unconventional Eagle Ford shale play. The first step of the integrated approach is the application of hierarchical clustering methods to identify electrofacies groups using log curves. Next, electrofacies are converted into lithofacies through an analysis of core data. The 3D lithofacies and petrophysical distribution model is then created using stochastic geostatistical techniques. In the reservoir simulation step, the discretized facies model is constrained to assign geomechanical properties. Thus, a realistic fracture model is generated with a proper definition of fracture characteristics to control flow simulation and to enable better history matching. The solution presented in this paper provides an objective means of using the integrated approach in an accurate definition of fracture properties, in terms of length and orientation, for reservoir simulation and production forecasting in unconventional reservoirs.
Gosain, Sonali (Cairn India Limited) | Dhiman, Mansi (Cairn India Limited) | Kothiyal, Manish Dutt (Cairn India Limited) | Upadhyaya, Akhilesh (Cairn India Limited) | Jetley, Shailendra (Cairn India Limited) | Jain, Sachin (Cairn India Limited) | Jain, Akanksha (Cairn India Limited) | Patel, Nilay (Cairn India Limited) | Hammond, Paul (Cairn India Limited)
Cairn India Limited operates over 600 wells in the Barmer basin in Rajasthan with over 30 well intervention (rig and rigless) units deployed on an average to perform over 5000 interventions per year. Maintaining the quality of interventions and analyzing the performance of such a scale of operations is a major challenge. This paper describes "An holistic approach" for evaluating well intervention campaigns, reviewing candidate selection, intervention techniques and technologies utilizing an intensive data warehouse and the techno-economical tool, "Scorpion Plot" to optimize intervention costs and rewards.
The performance of all Well & Reservoir Management (WRM) activities are analyzed in terms of cost and associated gain. The data gathered is categorized into four types namely Well Surveillance, Production Enhancement, Restoration, Well Integrity and Support. The expenditure on non-oil and gas gain generating interventions (Well Surveillance, Restoration, Well Integrity & Support) plotted on cumulative cost basis gave an overall idea of the health of the well stock and understanding of the value of information from data gathering. The Production Enhancement activities, sorted in increasing order of cost per barrel gained were plotted on a cumulative cost vs cumulative gain curve termed as "Scorpion Plot" because the shape always largely resembles a "scorpion tail" with low cost-high gain jobs lying in the bottom left part of curve and high cost and negative value interventions forming the "tail" of the scorpion to the top right. The analysis of the type of jobs falling in the different tranches of the plot on the basis of $ spent per barrel gained, helps in identifying the areas for optimizing the process of candidate selection and job execution.
The objective is to remove negative gain and reduce high cost low gain activities (the tail of the "scorpion plot") and shift the curve towards the bottom left to improve oil realization while reducing cost. After Action Reviews are carried out for all the negative and lower value activities and the lessons learnt are fed back into the intervention management system to enhance future intervention campaign results. Production enhancement activities such as ‘Well Stimulation’ positioned in the negative value group were further analyzed based on the selection criteria, technique of stimulation, chemical recipes/volumes were benchmarked against the high value interventions. Case studies showing how the analysis helped in better candidate selection and best technique for interventions are discussed.
This paper also describes how the process of candidate selection, cost, resource allocation and job impact assessment is automated ensuring engineering focus on job planning and after action review.
Drilling activity in Seram Island block is one of the most active in the Eastern Region of Indonesia. Drilling operator in the block has conducted drilling of 2 (two) exploration wells, where one of the well reached total depth to 19,230 ft. The well is one of the deepest onshore well in Indonesia. Both exploration wells have target to penetrate Manusela Formation as objective reservoir.
Actual drilling depth of the first exploration well LFN-1 in LFN field is 14,525 ft and the second well LFN-2 is 19,230 ft. The drilling effort in the LFN field faced many challenges, such as those experienced in LFN-1 well during drilling 8-1/2" hole section in Lower Nief formation whose lithology is limestone, partial loss occurred and in the consecutive formation of Kola with Shale whose lithology contained overpressure zone resulting in kick and well control effort has to be taken. This shows that the drilling operation in 8-1/2" hole section there is a narrow window of pressure regime between Pore Pressure (PP) and Fracture Pressure (FP) which is estimated to be ± 2 ppg. Thus drilling operator is required to use the latest method or technology to overcome the challenges and to finish drilling safely.
Efforts that were made to minimize operation problems in well LFN-1 have been analyzed and learned to be improvement on well LFN-2. One of the solutions selected was to use current well-known technology which is Manage Pressure Drilling (MPD) method on well LFN-2. The MPD is to be utilized on 8-1/2" hole section. The purpose of the application of the MPD method is to keep the Bottom Hole Pressure (BHP) to be constant in between Pore Pressure (PP) and Fracture Pressure (FP) thus minimizing the occurrence of losses and kick at the same time. The advantages of MPD usage are that we can make BHP constant during pipe connection so the hole does not allow kick and at the time of drilling, as it passes through the overpressure zone which is up to 17 ppg, the influx can be detected and anticipated quickly.
With the application of MPD method on LFN-2 well in 8-1/2" hole section, LFN-2 well could go according to plan and there was no problem as experienced before in well LFN-1. This is a good achievement in improving the performance of drilling at exploration wells with depth up to 19,230 ft.
Natural gas produced from underground reservoirs varies in its composition depending on the type, depth, and location of the underground deposit and the geology of the area. Natural gas is usually considered sour if the hydrogen sulphide (H2S) content exceed a certain threshold. And the term acid gas is usually used if it contains acidic gases e.g. carbon dioxide (CO2). Natural gas is called sweet gas when it is relatively free of H2S and CO2. The contaminants in natural gas needs to be treated or maintained within a certain limit as per the required pipeline quality for exports and sales. In Sarawak Gas Operations, the contaminants is being managed by means of integrated gas blending.
Field B is one of the deepest platform-type carbonate gas reservoir in Central Luconia Province, offshore Sarawak with highest level of contaminants i.e. 40 mol% of CO2 and 2800 ppm of H2S. Sampling at more frequent interval of twice a year is implemented to monitor the trending of the contaminants level which will give perception on the effective blending management and maximum gas recovery. The strategy to produce as much as sour gas first while ample sweet gas is available to achieve maximum overall gas recovery is well understood.
Observation on the trending for more than 10 years suggest that the level of contaminants is increasing by time and the field is souring. This finding is supported by the understanding of CO2 and H2S solubility in water which is higher as compared to hydrocarbon gases. The suspected mechanism for the reservoir souring is the changes in CO2 and H2S solubility in water with pressure change.
This paper summarises the main issue of increasing contaminants level and effort to maximise gas recovery from the souring reservoir and discusses on the results from contaminants level trending and example from analogue field.