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 reentry campaign to side track wells Mercury and Earth was planned to be executed in Q1 2018. The objectives of this paper are twofold: 1. Review the production performance of a granitic basement gas field and share learnings which may be useful for similar fields being developed elsewhere.
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.
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.
Abdulhadi, Muhammad (Dialog Group Berhad) | Tran, Toan Van (Dialog Group Berhad) | Chin, Hon Voon (Dialog Group Berhad) | Jacobs, Steve (Halliburton) | Wahid, Muhammad Izad Abdul (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
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.
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Nagar, Ankesh (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Pranay (Cairn Oil & Gas, Vedanta Ltd) | Nekkanti, Satish (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Preyas (Cairn Oil & Gas, Vedanta Ltd)
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
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.
Saikia, Partha Protim (Oil India Limited) | Dutta, Udai Anand (Oil India Limited) | Tumung, Ranjiti (Oil India Limited) | Verma, Sanjay (Oil India Limited) | Ahmed, Akhtar Uddin (Oil India Limited) | Mukerjee, Aditya (S.K.Oilfield)
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
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.
The variety and sophistication of upstream technologies have been growing fast for imaging the subsurface, modeling reservoir performance and monitoring oil and gas production. Yet there remains a fundamental need to thoroughly sample and analyze the produced reservoir fluids. Reservoir fluid analysis is critical for understanding the nature of produced hydrocarbons and is the key for production optimization. To gain the maximum value from this analysis, reservoir fluid sampling programs need to be well designed and integrated into well testing and reservoir surveillance programs, and not to be developed after. In one of Chevron's deep-water Gulf of Mexico (DWGOM) sub-salt fields, a robust geochemical sampling plan and production monitoring program has been in place since initial production to estimate the zonal contribution from individually stacked reservoirs. This surveillance work has been ongoing for 9 commingled wells over a period of 10 years.
In the petroleum industry, there is a need to accurately obtain downhole pressure to determine the distribution of flow rates at perforations in the wellbore, which can be used to quantify near-wellbore reservoir heterogeneity, such as major fracture conduits. Traditionally, electrical sensors are used to obtain the measurements, but fiber optics sensing has become more popular due to many advantages over traditional sensors, such as long-term durability and distributed sensing in harsh conditions. In addition, one of the most valuable measurement attributes that fiber-optic sensing could provide is a near-continuous recording of fluid pressure along the wellbore via distributed pressure sensing (DPS).
The measured pressure data along the wellbore from fiber-optic sensing can be used to calculate specific productivity index variations, which in turn, quantifies permeability spikes along the wellbore, such as high-permeability fractures and leaking faults. Because of the lack of field data, a proxy numerical model was developed to generate flowing pressure data in a horizontal wellbore. We then used a semi-analytical model to determine the permeability variations along the wellbore that yield the closest wellbore pressure profile to the simulated measured pressure, using the ‘interior-point barrier method’ algorithm. Several numerical examples, such as a single-phase and a water-oil flow, were examined.
Knowing the productivity of the reservoir along the wellbore allows operators to make quality decisions, leading to optimal reservoir development. In addition, one can generate a flow rate curve along the wellbore as a proxy to a production logging measurement. Furthermore, fiber-optic pressure sensing provides a continuous stream of valuable information, leading to reservoir description on a real-time basis.