PY-1 is one of the few fields in India producing hydrocarbons from Fractured Basement Reservoir. The field was developed with nine slot unmanned platform with gas exported through a 56 km 4" multiphase pipeline to landfall point at Pillaperumalnallur. Field was put on production in November 2009 with three extended reach wells. The production performance of the field had some surprise and declined earlier than expected. As a result, based on the conclusions drawn from an integrated subsurface study, a two wells re-entry campaign to side track wells Mercury and Earth was planned to be executed in Q1 2018. The objectives of this paper are twofold: Review the production performance of a granitic basement gas field and share learnings which may be useful for similar fields being developed elsewhere. Share the fit-for-purpose modelling workflow adopted to identify the opportunities and estimate reserves Methods, procedures, process The workflow consisted of following: Key uncertainties impacting GIIP and recovery were ascertained through subsurface and production data analysis Analytical reservoir engineering tools such as material balance was used to estimate GIIP from production and pressure analysis. Importance of having PDG installed in offshore wells with unmanned platforms are highlighted. The uncertain petrophysical parameters such as porosity and was constrained based on GIIP estimates from material balance Prosper models were used to understand and predict the well performance and optimal tubing size to avoid liquid loading Fit-for-purpose simulation models were constructed to quantify impact of key uncertainties on production forecast and recovery In order to mitigate the operational risks, drilling services were outsourced as a turnkey project to an industry leading service provider.

A matrix stimulation candidate screening workflow was developed with the objective to reduce the time and effort in identifying under-performing wells. The workflow was initially tested manually for few fields followed by inclusion in Integrated Operation for an automated screening of wells with suspected formation damage. Analysis done in three fields for stimulation candidate selection will be displayed with actual statistics. The main aim of the work was to digitalize the selection of non-performing candidates rather than manually looking into performance of each well. A concept of Formation Damage Indicator (FDI) was combined with Heterogeneity Index (HI) of the formations to screen out the candidates. Separate database sets of Reservoir engineering, Petrophysicist and Production was integrated with suitable programming algorithms to come up with first set of screened wells evaluating well production performances, FDI and HI trends up to over the last 30 years. The shortlisted candidates were further screened on the basis of practical approach such as gas lift optimization, production trending, OWC-GOC contacts, well integrity and well history to come up with second round of screened candidates. The final candidates were analyzed further using nodal analysis models for skin evaluation and expected gain to come up with type of formation damage and expected remedial solution. For fields A and D with a total of 210 strings each, the initial FDI and HI screening resulted in 70 and 120 strings being shortlisted, respectively. This was followed by a second round of screening with 25 and 35 strings being further shortlisted as stimulation candidates, respectively. Nodal analysis models indicated presence of high skin in 90% of the selected wells indicating a very good efficiency and function-test of the workflow. In addition to selection of the candidates, the identification of formation damage type was compiled on an asset-wise basis rather than field basis which helped in more efficient planning of remedial treatments using a multiple well campaign approach to optimize huge amount of cost. The entire screening process was done in one month which was earlier a herculean task of almost one year and much more man-hours. With effective manual testing of the workflow in two major fields, workflow was included in Integrated Operations for future automation to conduct the same task in minutes rather than months. With this digitalized unique workflow, the selection of under-performing wells due to formation damage is now a one click exercise and a dynamic data. This workflow can be easily operated by any engineer to increase their operational efficiency for flow assurance issues saving tons of cost and time.

In any onshore gas installation, bath-heaters and high pressure separators are provided as standard surface facilities to take production from high pressure wells having hydrate forming tendency. Medium pressure separators are also provided to take production from medium pressure gas wells. The paper deliberates on an optimized surface installation for handling high pressure well fluids with possibilities of hydrate formation. The study has been carried out through steady state multiphase simulation considering pressure & production profile of the wells, consumer requirement and flow assurance i.e. hydrate formation. An optimized process scheme and production strategy is presented for early production from both high pressure and medium pressure gas wells in a single separator and without any bath heater. Based on well test data, well completion data and pressure profile, simulation studies are carried out in steady-state multiphase flow simulation software to look into possibility of hydrate formation in the flow lines or in process piping. Flow from wells having high well-head pressures in the range of 120 to 165 kg/cm 2 g (ksc) are simulated by varying the separator pressure, flow line size & length and choke arrangement. Flow simulations are carried out for different choke combinations and flow line arrangements to keep well fluid temperature above hydrate formation temperature in the entire flow path from well head to separators. It was established from simulations that flow from the well having highest production as well as highest well head pressure of 165 ksc can be taken by operating the separator at 33 ksc and adopting a multi-choke arrangement along the flow line without any possibility of hydrate formation in the system. The multi-choke arrangement consists of putting chokes including well head choke at well site, at installation inlet and the final choke at installation inlet manifold. The arrangement also envisages additional small length of flow line as buried portion near installation inlet to take advantage of heat gain from soil. From 2 nd year onwards of the profile period, it is observed that with reduction in well head pressure to 132 ksc as per profile, the well can be produced by operating the separator at lower pressure without any hydrate formation. For rest of the wells, only multi-choke arrangement is found to be sufficient to prevent hydrate problem while operating the separator at even lower pressure throughout the profile period. It is also observed that higher production can be taken from the wells from 2 nd year onwards on account of operating the separator at lower pressure. The optimized scheme has marked deviation from the earlier proposed standard scheme with substantial reduction in number of equipment and consequent reduction in CAPEX & OPEX. This novel process scheme and production strategy eliminate the need for investment in both high pressure separator and hydrate mitigation measures like heat tracing, methanol injection or bath-heaters. This innovative production strategy also facilitates better recovery from the gas wells on account of operating the separator at lower pressure.

Radial jet drilling is a widely used environment friendly technique to improve well productivity in tight reservoirs, accelerate production in low-to-medium permeability wells, revamp production in mature wells with formation damage. This technique has helped to enhance production from mature field by bypassing skin, extend the connectivity of the wellbore beyond the near well bore area by drilling laterals using high pressure water jet, and thereby alleviate production restrictions caused by near well bore damage and extend the reach of the wellbore far into the formation. Production, being dependent on reservoir contact of the well bore is therefore increased as average reservoir contact is enhanced by the drain holes. However, selection is equally important as all wells cannot be considered as a suitable candidate and unsuitable candidate selection can show detrimental outcomes. The technology was applied in a sandstone reservoir where a 22 mm hole was created in the casing at the target depth and then 50 mm OD lateral of length 100m was drilled in the reservoir using high pressure hydraulic jet. The accurate placement and orientation of downhole tool plays a significant role in the success of this technology and is found to be always challenging. Preventing casing milling in undesired azimuths, eliminating chances of lateral overlapping are some challenges that essential to be addressed for gaining optimum advantages. One of the promising technologies to address these challenges was the application of Surface Recording Gyro System. The application of surface recording gyroscopic well bore navigation system provides accurate placement of tool for lateral exit in the down hole and thus enable creation of lateral in the desired direction. This paper discusses candidate selection and execution carried out in 7 nos. of wells in OIL INDIA LIMITED utilizing surface read out gyro system, which was done for the first time in INDIA . This paper also discusses about a post job analysis and lesson learnt with depths varying from 2414m to 3472m , the deepest well in India where radial drilling was carried out successfully. Post radial drilling on wells which had no/poor production prior to radial drilling showed very encouraging results. It also details about criteria of well selection, step by step procedure of the process, bottom hole tool selection, jetting and milling fluid used along with function, application, advantages of surface read out gyro system. As stimulations and well preparation in complicated wells are capital intensive, it was critical to identify the most-suitable candidates with the available dataset before attempting well preparation and further acquisition. This was addressed through a customized workflow to design and creation of the horizontal laterals in desired azimuth utilizing the surface readout gyro system along with radial jet drilling for maximizing oil recovery.

Infill Well B-23, which was recently drilled in the CIII-2 reservoir located in the Balingian Province, experienced a rapid pressure and production decline. The production decreased from 2,200 to 600 BLPD within 1 year. Analysis of the permanent downhole gauge (PDG) data revealed that Well B-23 production was actually influenced by two other wells, B-20 and B-18, each located 2,000 ft away. This paper discusses the ensuing analysis and optimization efforts that helped reverse the Well B-23 pressure decline and restored its production to 2,200 BLPD. Based on the typical causes of rapid production and pressure decline, operators initially believed Well B-23 was located in a small, separate compartment compared to Wells B-18 and B-20. Additionally, the Well B-23 behavior differed significantly from Wells B-18 and B-20. PDG data analysis provided clear evidence of well interference despite the significant distance between the well locations. Changes in the other wells immediately affected the Well B-23 pressure, thus leading to the conclusion that production from Wells B-20 and B-18 impeded the pressure support for Well B-23. To optimize Well B-23 production, Well B-20 was shut in while Well B-18 was produced at a reduced rate because of a mechanical issue. The optimization initially resulted in more than 500 BOPD incremental oil from Well B-23. The well pressure decline was reversed, with PDG data showing a continuous increase of bottomhole pressure (BHP) despite an increase in the production rate. Subsequently, production was fully restored from 600 to 2,200 BLPD, and reservoir pressure returned to its predrill pressure. Going forward, the optimum withdrawal rate from the CIII-2 reservoir will be determined to ensure maximum oil recovery from both Wells B-18 and B-23. The case study proved the significant benefit of PDG data, which helped identify well interference as the actual cause of the rapid decline in Well B-23, instead of a reservoir or geological issue. Through in-depth analysis and thorough understanding of the reservoir, the operator restored what initially appeared to be a poor well to full production. This case study shows the clear and strong effect of well interference and highlights how the subsequent results of the optimization effort were rapidly obtained. A comprehensive understanding of the reservoir behavior could not have been achieved at minimum cost without the pair of PDGs installed. The analysis and lessons learned from the Well B-23 PDG data provide valuable insight regarding the impact of well completions to the field of reservoir engineering.

This paper describes simulation solution for CT(Coil Tubing) based WBCO in flowing ESP/Jet Pump wells for scale/polymer debris deposition removal prior to any treatment in well, such as – Formation stimulation, ESP treatment, etc. It also describes prediction for requirement of Surface Well Test spread support to assist Nitrogen assisted WBCO. The paper describes new way of simulation for CT WBCO job in artificially flowing wells to predict decreased Liquid rate from reservoir, CT pressure & friction pressure losses. The modelling is done in Prosper and Cerberus, the results of which are validated with surface well test and Multiphase flow meter data recorded during the jobs. The results observed were very close to modelled with a number of advantages such as – No loss returns, higher lifting velocities, prediction of increased/decreased reservoir liquid rate affecting Motor winding temperature in ESPs, no settling of debris, post job Increased Liquid gain from well, decreased tubing friction pressure loss

Barmer Hill Turbidites (BHT) are low permeability reservoirs in the Vijaya & Vandana field with an approximate in place reserve of a billion barrels. The field was discovered in 2004 with the discovery wells V-1 and V-2 respectively. Post drilling and completion these wells were tested without any stimulation technique, resulting in ~ 25 – 50 BOPD flow owing to tight nature of these formations. Subsequently the zones were hydraulically fractured and tested resulting in ~ 10 – 12 folds increase in the production rate of the oil. Also, the testing of multiple stacked reservoirs in these two wells further confirmed BHT-10 to be the most prolific zone in terms of commercial flow rates achievable. Apart from being tight formations, the low net to gross on reservoirs (<20%) further added to the challenges of devising a strategy to make these reservoirs flow at sustained commercial oil rates. Hence, when the field was taken for the next stage of a hydrocarbon field lifecycle i.e. the appraisal campaign, two very clear objectives were identified for achieving a successful appraisal campaign viz. hydraulically frac and test two of the existing wells in the field while aiming to connect the maximum available KH and ensure effective data acquisition through injection tests and temperature logs with an aim to calibrate the existing stress logs and eventually build a robust frac model. The dynamic geo-mechanical parameters i.e. Young’s Modulus and Poisson’s Ration were calculated from the open hole sonic logs and were converted to static data using the lab measured value from the core tests. Stress logs generated from these static data points were used for the initial frac designing in the wells. During the execution phase of the frac campaign, at every opportunity available, injection tests were carried out and fall off data were acquired to estimate the closure pressures actually observed in these zones. Post acquiring the measured stress data, the earlier calculated stress logs were calibrated using these measured closure points (frac gradients) by incorporating the stress components due to strain factors (ɛmin & ɛmax) in both max and min direction of the principle stresses. Post every data injection, temperature logs were also acquired. This gave a better control on frac height (hydraulic height) based on the cool downs observed on the temperature logs. This proved to be a very important data set in comparing the height predicted by the calibrated stress logs versus the height estimated from the temperature log cool downs. This step helped in gaining confidence on the model predictability. This also helped in real time frac design optimization and placement of perforation intervals for the main frac designs. Further, the entire model calibration exercise also helped in arriving at a porosity based leak off equation. The paper endeavors to discuss in detail the entire workflow used during this appraisal campaign to arrive at a calibrated and a robust frac model whilst showcasing the journey taken from 50 BOPD to 500 BOPD in these tight oil sands to achieve ~ 10 fold production increase. Authors, further, emphasize on the importance of carrying out such data acquisitions during the appraisal phase of a field to gain better control on the models. This paper will also elaborate on the strategy deployed for these data acquisition to optimize the fracs in real time and to integrate different data sets for calibrating the geo-mechanical and frac simulation models.

Vertical Interference tests (VIT) are used to determine the hydraulic connectivity between the formation sand intervals. This paper showcases an innovative workflow of using the petrophysical log attributes to characterize a heterogeneous reservoir sand by making use of ANN (Artificial Neural Net) and SMLP (Stratigraphic Modified Lorentz) based rock typing techniques as well as image based advanced sand layer computation techniques. Vertical interference test is either performed using a wireline formation testing tool with multiple flow probes deployed in a vertical sequence at desired depth points on the borehole wall or using a drill stem test configuration. Based on the test design, flow rates are changed using downhole pumps, which induces pressure transients in the formation. The measured pressure response is then compared with a numerical model to derive the reservoir parameters such as vertical permeability, hydraulic connectivity etc. The conventional way of model generation is to consider a section of reservoir sand as homogenous, which generally leads to over estimation or underestimation of vertical permeabilities. The technique proposed in this paper utilizes advanced logs such as image logs; magnetic resonance logs, water saturation and other advanced lithology logs to obey heterogeneity in the reservoir model by utilizing ANN/SMLP based rock-typing techniques. These rock types would be helpful in making a multi layer formation model for the VIT modeling and regression approach. The vertical interference test model is then used to determine the vertical permeability values for each of the individual rock types. The paper displays the workflow to utilize the rock type based layered formation model in vertical interference test modeling for a channel sand scenario.

Proper and reliable resource assessment of hydrocarbons in-place and recoverable volumes is one of the key factors in field development planning (FDP) and determines the commitments made to the host government for the reserves to be developed (RTBD). Many times, it is critical to update the resources and reserves of a producing asset through full field reviews (FFR) to gauge the production attainment and success of initial forecasts in FDP and also to locate any upside/locked-in potential. Often uncertainties in the field development are expected to reduce as the field produces, but in many cases the results show otherwise due to lack/ inaccuracy of data or existing reservoir complexities. This paper elaborates how an integrated approach utilizing analytical methods (material balance, pressure and rate transient analysis) combined to numerical reservoir simulation is used for accurate resource assessment of an over-pressured gas condensate reservoir that suffers from lack of geological and petrophysical data, faulty production data measurement system and complex fluid and pressure behavior. A comprehensive workflow comprising of different methodologies is used to harness the available geological, petrophysical, production and pressure data. Over-pressured and compressibility corrected gas material balance and pressure and rate transient analysis (RTA) are conducted using static and flowing data to encompass the existing uncertainties on resource numbers and generate low, base and high cases. The results of these methods are then successfully utilized to construct the dynamic reservoir model for evaluation of the upside and near field exploitation (NFE) potential. The results of the full field review lead to a 50% increase in the gas initially in-place compared to FDP volumes and a significant addition in the proven reserve. This increase in volumes was investigated through proactive surveillance for a period of time and was well supported by the reservoir and well performance. A novel approach to numerically model the over-pressured gas reservoirs is developed using a simple concept of compressibility modifications supported by production data history match and analogue core data. The results of the study greatly benefited the production sharing contract (PSC) and lead to production enhancement from the field through a proper debottlenecking project.

Well interference in unconventional CBM reservoirs is often desired. It reduces reservoir pressure; significantly increasing gas production through desorption. However, identifying interference between wells and extracting quantitative reservoir information using production data analysis is a challenge. The primary objectives of this study are to identify production characteristics of interfering CBM wells, evaluate reservoir parameters, demonstrate the application of interference data using field examples to predict well performance and develop guidelines to optimize geospatial well-pattern. A field wide interference study has been undertaken to track changes in gas rate, water rate, wellhead pressure and fluid level in each well. An ‘event-based’ filter is applied to the dataset to correlate production behaviour of a well with any unplanned ‘event’ in its offset well. Planned well tests are then conducted to ascertain these evidences of interference. Using production data analysis of interfering wells, a set of semi-analytical correlations have been developed based on the transient drainage radius model to determine production-governing permeability of coal formation, and also quantify the flow contribution of natural fractures and reservoir matrix. Preliminary analysis of the study demonstrates several forms of interference. Well specific field examples have been presented for each case. Interference between producing wells having long production history show a trend reversal in gas flow rate due to additional dewatering support by its offset well. Similar behaviour is observed in the production characteristics of an old producer when a new well is drilled in a nearby location. However, effects of interference are more dominant when a well stimulation activity (fracturing or re-fracturing) is carried out in an offset well. During stimulation activity, offset wells show an abnormal decline in gas rate and wellhead pressure due to fracking fluid (water) load up in the reservoir. Conversely, a significant positive impact is seen in gas rate of both wells after the well is put back on production due to improved water production rate in the stimulated well. Permeability calculations show that natural and artificial fractures dominate production behaviour of CBM wells. The study also presents results of various simulated geo-spatial well patterns. Furthermore, it is shown that planned interference at an early time with an economically designed well spacing can maximize the production NPV of an asset for an operator. The optimal well spacing to maintain and/or increase gas production with the right amount of resources is critical for maximised returns. This result of this study can be used as foundation to help operators optimize multi-well pad and future infill well development program based on the assessment of short-term and long-term recovery targets.

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 (H 2 S) content exceed a certain threshold. And the term acid gas is usually used if it contains acidic gases e.g. carbon dioxide (CO 2 ). Natural gas is called sweet gas when it is relatively free of H 2 S and CO 2 . 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 CO 2 and 2800 ppm of H 2 S. 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 CO 2 and H 2 S solubility in water which is higher as compared to hydrocarbon gases. The suspected mechanism for the reservoir souring is the changes in CO 2 and H 2 S 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.

Declining reservoir pressure, increasing water cuts along with dwindling well counts pose a serious challenge to any mature oil and gas field in sustaining production. In low oil price scenarios, enhancing production using conventional approaches like workover and interventions becomes challenging due to associated costs. This provided an opportunity to look for alternate approaches that are cost-effective and would help to manage these issues on a continuous basis. This paper presents techniques for augmenting productivity of well stock by mitigating a range of issues causing production losses using cost effective, easy to implement chemical based techniques. These techniques have helped the asset to significantly arrest its production decline in the late life phase. This paper details the approach for identification of issues, selection and field implementation of right chemicals and the benefits that were realized from such applications. Case studies from BG Exploration and Production India Limited (BGEPIL) operated field in Mumbai offshore region are incorporated in this paper to highlight the effectiveness of chemical based approach in mitigating losses right from reservoir to processing platform. Some of the production issues in this mature field which have been successfully resolved using chemical based techniques are: Reservoir: ○ Loss of well stock due to Downhole emulsion issue Well: ○ Calcite Scaling deposition in wells and topsides ○ Liquid loading of High Gas Liquid Ratio wells Pipelines: ○ Back Pressure on wells due to Pipeline size limitation Processing Facilities: ○ Deterioration in Heat Exchanger performance due to fouling Process adopted includes field data acquisition, analysis using real time state-of-the-art network and process models to identify the root cause of these issues. Results from both steady state and transient models were used to select the appropriate chemicals, conduct field trials / implementation and set the success KPI's accordingly. This paper offers a holistic approach on resolving each of the discussed production issues utilizing the best available technology in the market. Trials and implementation of the various chemicals in the field have added a significant value to the asset; both by protecting and enhancing the current production. More than 20 % of current field production is directly attributed to these chemical applications and expected to add more share of production in a far more challenging phase of mature asset. The approach discussed here for each of such production issues along with the challenges that were faced during implementation will enable other assets to tackle these problems with a more cost effective and easy to implement solutions especially in low oil price environment.

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.

Objectives/Scope 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. Methods, Procedures, Process 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. Results, Observations, Conclusions 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. Novel/Additive Information 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

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.

The NE field is located in Barmer Basin, Rajasthan, India. The field is on production with two wells since March 2015 and is currently producing about 1100 bopd. Both the wells are completed with progressive cavity pumps (PCPs). Production is being carried through a small production facility (QPF). The presence of pumps in the well makes the acquisition of pressure build up (PBU) data complex. However, gathering a PBU was considered an important part of gauging reservoir performance. This paper details how an echo-meter was used in one of the wells for acquiring Pressure Build Up data. The echo-meter was used to measure dynamic fluid levels in the casing-tubing annulus; these were used to estimate reservoir pressure and other properties in a cost effective manner. The paper discusses a systematic approach in echo-meter based well test design, execution challenges and the PTA of the acquired data. The well was flowing with a drawdown of about 100 psi and the liquid level in the annulus was about 100m from the top. The direct collection of PBU data would have required a work-over to remove the pump to place the gauge. This would need to be repeated to retrieve the gauge. A novel & cost effective approach was required to acquire pressure build up data. An alternate option was acquiring the pressure data indirectly by measuring the continuous dynamic level in the annulus using an echo-meter. Although this option had its own challenges, it was economically justified. The required number of echo-meter shots and frequency of the shots was selected based on well test design. The test design provided guidance on the pressure build up rate required for damaged (skin) and non-damaged conditions, permitting us to identify the pressure build up duration and the optimum frequency of the echometer shots. One challenge was concern over annulus liquid level rise in the wellbore. This was addressed prior to the build-up by injecting nitrogen into the annulus to reduce the liquid level in the annulus. This mitigated the possibility of liquid level rise in the annulus to the wellhead. The quality of the pressure data acquired through echometer shots was good enough for carrying out pressure transient analysis. The pressure derivative plot was constructed and information on skin & permeability was obtained. Radial flow signature was clearly observed. The average reservoir pressure value as well as the permeability agreed with expectations. The impact of uncertainties on the final interpretation was evaluated and found to be in acceptable range. In current oil price environment and in marginal fields like NE, where there is always a constraint on economics, this low cost technique can be a vital tool for effective reservoir management.

The Raageshwari Deep Gas Field (RDG), Barmer Basin, India, is a thick (~900m gross), low permeability (0.01-1md) gas condensate field (CGR: ~70 STB/MMscf). The pay-zone consists of a poorly sorted sandstone interval on top of stacked succession of volcanic lava flow cycles. The field is being developed through multi-stage hydraulic fracture stimulations to allow production at economical rates. Recently two hydraulic fracturing campaigns comprising of 125 stages in 20 wells were successfully completed which have resulted in significant improvement in well productivity. This paper highlights the integrated workflow applied in a volcanic reservoir to reduce subsurface uncertainty and value addition in optimizing hydraulic fracturing operation. To account for the complexity associated with volcanic rocks, a fit for purpose integrated petrophysical and geomechanical workflow was developed using a basic wireline logs, processed NMR, dipole sonic and image log analysis. The model was calibrated with dynamic data especially diagnostic fracture injection test (DFIT), pressure build up and production logging tool (PLT) analysis. The final calibrated model was used to identify the net reservoir packets along the well length, which further helped to identify the optimum locations to create hydraulic fractures. A typical log motif generated using the integrated model is given in Figure-1 . As seen on the generic log in Figure-1 , net reservoir intervals are in multiple packets of varying thickness contained throughout the thick gross reservoir package. Connecting maximum net reservoir packets through hydraulic fractures is critical for maximizing the well productivity and EUR. The limited entry fracturing technique ( Lagrone and Rasmussen, 1963 ) was used to connect the maximum net reservoir with a fewer number of stages and a lower cost. Extensive data acquisition (extended DFIT, formation wise testing, PVT sampling, PLT and pressure build-up) was carried out to increase reservoir understanding followed by detailed subsurface modeling. The extensive data acquisition programme was successful in reducing a number of uncertainties, including: reservoir information, effective fracture parameters and presence of natural fractures. The key outcomes from the two frac/data acquisition campaigns are as follows: The integrated petrophysical and geomechanical model enabled us to improve the net connected reservoir by 65% in the volcanic sections The optimisation of the number of frac stages and their cost An improved subsurface understanding in well deliverability, frac conductivity, half-length and frac height Confirmation of gas contribution from each perforation and the establishment of deeper gas which validated petrophysical pay A new, more accurate, poro-perm transform calibrated with permeability estimation using DFIT and pressure build up A better subsurface understanding which supports higher estimates of GIIP and EUR

Modern advancements in technologies pertaining to the drilling of horizontal well and multi stage hydraulic fracturing have made it possible to get significant hydrocarbon production even from extreme low permeability formations. However, correct evaluation of the economics of the project is becoming increasingly essential before committing to any big investment. In this scenario, production forecasting based on reservoir simulation plays an important role by not only evaluating the economic feasibility of the project, but also helping in the selection of the most optimal development strategy. In this paper, a workflow has been demonstrated that proved useful in addressing such challenges related to the tight reservoirs (permeability less than ~2mD). The methodology adopted in this study can be divided into two parts. The first part involves data preparation for single well numerical modeling similar to Daungkaew et al (2008) and Kumar et al (2008). This includes building a petrophysical model based on the mineralogy characterization and also carrying out Rate Transient Analysis (RTA) for permeability estimation using the data acquired from an existing well ( Pan et al, 2011 ). RTA is preferred over the conventional buildup analysis as it does not require shutting of the well. The second part of the workflow involves creation of a numerical model based on the petrophysical, PVT and SCAL data. Hydraulic fracture (if present) is modeled by editing the permeability of the grid cells falling under the fracture geometry. The model is calibrated with the production data after initializing with the pressure and fluid contacts. The history matched model is then used to generate production forecasts of multiple scenarios including horizontal well with multiple stages of fracturing and sensitivities can be made with respect to drainhole length, fracture stages etc. Furthermore, economic analysis can be carried out to select the most economically viable case. The proposed workflow has been applied in one of the low permeability oil field in India. The permeability derived from RTA was in close agreement with the core results. This workflow was used to generate production forecasts for multiple development scenarios. It was used to optimize the number of fracture stages, keeping the drainhole length constant. In this paper, a novel approach is discussed that combines the RTA and single well numerical modeling technique to evaluate different strategies of producing from a tight reservoir. Based on the economic analysis then, one can maximize the return.

The petroleum industry is faced with a number of enormous challenges resulting from the declining oil prices such as high abandonment and new wells construction costs, low sweep efficiency, harsh environments etc. These challenges can be met by designing a long term field development plan of a petroleum prospect, ensuring maximum recovery without sacrificing the safety standards. This work describes a multicomponent and strategic development plan designed for a tight gas reservoir, starting from formation evaluation to drilling-completion and economic analysis in addition to the environmental issues that must be considered in advance. The authors also acknowledge the support of: The field is principally a gas condensate field, where the reservoir is mainly Chalk with an average porosity of 27% and average permeability of 0.1mD with 65% water saturation. The reservoir pressure (5960 psia) and dew point (5940 psia) being very close, the reservoir is close to saturation pressure and gas condensate is expected to form immediately on commencing production. PVT studies indicated that the critical condensate saturation will not be reached which in turn means that it will never be mobile or recoverable with reservoir pressure decline. Given the fact that the water drive is rather weak, pressure maintenance methods will be needed to avoid the condensation of gas within the reservoir. Based on petro-physical evaluation, our team was able to construct a static reservoir model using Petrel Software and the team suggested three different development scenarios consisting of horizontal and multilateral wells of various configurations. Based on the development strategies, a dynamic model is constructed for each scenario to compare the techno-economic feasibility and selection of the most optimum strategy. It was found that the field would be economically viable to produce for a time period of 50 years and the simulation results indicate that an ultimate recovery of 69-76% was achieved if water injection is applied from year-1 onwards. Moreover, the highest recovery factor of 76% is achieved with scenario-B as it has a five spot pattern with 8 vertical injection and 3 multilateral production wells. In addition, the most delayed water breakthrough is achieved in this scenario that occurs after 2.5 years. Moreover, it was also observed that the pressure maintenance was 100% effective in scenario-C as the reservoir pressure increased as a result of increasing the water injection rate rather than increasing the sweep efficiency. However, for the other scenarios, the reservoir pressure drops but not below the critical value. Finally, a cumulative gas production of 389-424 MMMSCF was observed along with a gas production rate of 8.61-24.7MMSCF/day giving a cumulative net present value of $890,000 with a payback period of 5 years, indicating that the project is economically viable after 50 years.

The purpose of pumping out water from CBM well is to depressurize the coal seam to initiate desorption of hydrocarbon gases, mainly methane. Determination of accurate liquid level is required to calculate gas flow rate and well performance, to optimize pump sizes for maximum possible liquid withdrawal, for optimizing gas production, determination of pump setting depth for its optimum performance in view of NPSH and simultaneously to ensure water level to go down below the last coal seam. However, in CBM wells once critical desorption pressure is achieved, the water level monitoring gets complicated due to violent degassing and foaming. The liquid column in casing/tubing gets aerated by the gas produced from the coal seams. This paper presents a case study done in Raniganj coal block, West Bengal, India, which is one of the major CBM block in India. The total CBM acreage of the Raniganj CBM gas field is about 500 Sq Km. The study was done to calculate foam free liquid level with the use of mathematical formulae and portable surface acoustic liquid level measuring instrument which is quite simple and cost effective method to calculate accurate liquid level in wells that are producing considerable amount of gas, without any downhole intervention and on wells where installation of permanent gauges is not economical. The study was done in different wells where the calculated foam free liquid level was compared with results obtained from permanently installed pressure gauges and the results were found to be quite consistent. Hence, an accurate study of liquid level can be done in CBM wells which could be further used to optimize the production without compromising on accuracy of data with minimal cost, effort and resources.