This paper covers the problem related to AC interferences on East West Gas Pipeline (EWPL) and the mitigation measures taken for reducing / eliminating the same. AC interference was observed in Hyderabad region due to AC EHV Transmission lines crossing EWPL, three phase transformers and Single wire earth return (SWER) single phase transformers in the vicinity of pipeline. AC PSP voltage up to 80 Volts were observed on pipeline during night hours for which various mitigation measures were taken to bring down in acceptable range. Similarly, there is possibility of high voltage surge at station facilities along the pipeline route due to vicinity of multiple structures, long pipeline length and having multiple conducting structures at MLV stations comprising of RTD's, die-electric isolators, impulse Tubing for power gas and associated power gas and control equipment. Surge travel to such system can result in equipment failures. Various proactive measures to mitigate such instances were adopted on pipeline system and are implemented successfully. This paper illustrates the extent of the risk of corrosion, surge impact due to AC interference / surge and gives insight to various methods deployed for minimizing these risks in simple and most economical way. It also highlights the need for collaboration and operational coordination between the pipeline operators and state electricity boards to resolve such issues mutually & in most effective manner.
Abdulhadi, Muhammad (Dialog Group) | Tran, Toan Van (Dialog Group) | Chin, Hon Voon (Dialog Group) | Jacobs, Steve (Halliburton) | Suggust, Alister Albert (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
The first successful natural dump-flood in the Malaysian offshore environment provided numerous lessons learned to the operator. The minimal investment necessary for implementing the dump-flood coupled with the lack of recompletion opportunities in the subject wells suggested that direct execution without spending on expensive data gathering activity and extensive reservoir study makes more sense from a business point of view. A similar oil gain compared to a water injection project can be achieved at a significantly lower cost of USD 0.01 to 0.15 million in an offshore environment through dump-flooding.
The existing oil producers in the depleted reservoirs in Field B were originally completed and successfully drained oil from in a high-pressured watered-out reservoir below, making it an ideal dump-flood water source. The dump-flood was initiated by commingling the target and water source reservoir through zone change, allowing water to naturally cross-flow into the pressure depleted target reservoir. Once a memory production logging tool (MPLT) confirmed the cross-flow, the offtake well was monitored to determine the impact of the dump-flood and produce once the pressure was increased. Minimal investment was necessary because the operations were executed using slickline. The reservoir model will be calibrated once the positive impact of dump-flood is realized in the offtake well.
The first natural dump-flood in Reservoir X-2 has successfully produced 0.29 MMstb as of August 2018 with 600 BOPD incremental oil gain. The incremental recovery factor (RF) from the first dump-flood is predicted to be from 5 to 8%. Based on this success, it was decided to replicate the dump-flood project in other depleted reservoirs with Reservoir X-2 as an analog. Four reservoirs were subsequently identified, each with an estimated operational cost of approximately USD 0.01 million and potential incremental reserves of 0.10 to 0.20 MMstb per reservoir. The minimal investment necessary, the idle status of the wells and reservoirs, and the potential incremental reserves suggested that it is more appealing to proceed with implementing the dump-flood without undergoing an extensive and costly reservoir study. With reservoir connectivity being important to the success of dump-flooding, a more cost-effective approach would be to confirm the connectivity by monitoring the offtake well after the dump-flood is initiated. This approach provides more value because the cost of interference or pulse testing is significantly more expensive than the cost of the dump-flood itself while reservoir connectivity was already indicated as likely by geological data (map and seismic). Through a value driven approach, these dump-flood opportunities become more economically viable, allowing the operator to prolong the life of the assets and maximize the field profit.
This paper discusses using a value driven and business approach to implement the dump-flood in a mature field. Valuable insight into the business and technical considerations of implementing dump-floods are described, which are relevant to the industry, especially in today's low margin business climate.
Khare, Sameer (Cairn Oil & Gas vertical of Vedanta Limited) | Baid, Rahul (Cairn Oil & Gas vertical of Vedanta Limited) | Prusty, Jyotsna (Cairn Oil & Gas vertical of Vedanta Limited) | Agrawal, Nitesh (Cairn Oil & Gas vertical of Vedanta Limited) | Gupta, Abhishek Kumar (Cairn Oil & Gas vertical of Vedanta Limited)
The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study.
Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously.
The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction.
The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost.
The significant temperature difference between the fractured and non-fractured regions during the stimulation fluid flow-back period can be very useful for fracture diagnosis. The recent developments in downhole temperature monitoring systems open new possibilities to detect these temperature variations to perform production logging analyses. In this work, we derive a novel analytical solution to model the temperature signal associated with the shut-in during flow-back and production periods. The temperature behavior can infer the efficiency of each fracture. To obtain the analytical solution from an existing wellbore fluid energy balance equation, we use the Method of Characteristics with the input of a relevant thermal boundary condition. The temperature modeling results acquired from this analytical solution are validated against those from a finite element model for multiple cases.
Compared to the warm-back effect in the non-fractured region after shut-in, a less significant heating effect is observed in the fractured region because of the warmer fluid away from the perforation moving into the fracture (after-flow). Detailed parametric analyses are conducted on after-flow velocity and its variation, flowing, geothermal, and inflow temperature of each fracture, surrounding temperature field, and casing radius to investigate their impacts on the wellbore fluid temperature modeling results.
The inversion procedures characterize each fracture considering the exponential distribution of temperature based on the analytical solutions in fractured and non-fractured regions. Inflow fluid temperature, surrounding temperature field, and after-flow velocity of each fracture can be estimated from the measured temperature data, which present decent accuracies analyzing synthetic temperature signal. The outputs of this work can contribute to production logging, warm-back, and wellbore storage analyses to achieve successful fracture diagnostic.
Devshali, Sagun (Oil and Natural Gas Corporation Ltd.) | Manchalwar, Vinod (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.) | Malhotra, Sanjay Kumar (Oil and Natural Gas Corporation Ltd.) | Prasad, Bulusu V.R.V. (Oil and Natural Gas Corporation Ltd.) | Yadav, Mahendra (Oil and Natural Gas Corporation Ltd.) | Kumar, Avinav (Oil and Natural Gas Corporation Ltd.) | Uniyal, Rishabh (Oil and Natural Gas Corporation Ltd.)
The paper describes the feasibility of revisiting old sands, for improving the recovery factors and enhancing production, which otherwise were already abandoned. The paper also outlines the systematic methods for predicting the onset of liquid loading in gas wells, evaluation of completions for optimization and comparison of various deliquification techniques. ONGC is operating in two gas fields in eastern and western regions in India. Earlier in both the fields, many sands had to be closed/isolated after the wells ceased to flow due to liquid loading in the absence of continuous deliquification. In order to predict liquid loading tendencies and identify opportunities for production enhancement, performance of 150 gas wells has been analyzed. To select most suitable deliquification technique for the present condition, all technically feasible methods have been evaluated and compared in order to get the maximum ultimate gas recovery possible.
After an extensive study, 3 wells were identified in the preliminary stage and SRP was selected as the most suitable Deliquification technique. Initially, two non-flowing wells, which had ceased due to liquid loading and were about to be abandoned, were selected. After SRP installation and sustained unloading of water for about 30 days, these wells started producing 12000 SCMD gas. In the third well, one of the top sands had earlier been isolated due to liquid loading and production history indicated that the isolated sand had a very good potential. Also, production from the well was declining in the current bottom operating sand as well due to liquid loading. Encouraged by the results that deliquification had yielded in the initial two gas wells, the isolated sand interval in the third well was opened again with the aim to revive production. The well was re-completed with SRP with both the reservoirs open. Before deliquification, the well was producing about 15000 SCMD gas from the bottom sand. After SRP installation and continuous deliquification, the well started producing gas at a stabilized rate of 45000 SCMD, thereby resulting in an additional gas recovery of 30000 SCMD for nearly one year as on date. The approach of putting in place continuous deliquification techniques has not only helped in enhancing production from the existing reservoirs, but has also opened up new avenues to revisit the earlier isolated / abandoned reservoirs for possible enhanced recoveries.
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.
Gupta, M K (Oil and Natural Gas Corporation Ltd) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd) | Singh, V K (Oil and Natural Gas Corporation Ltd) | Pawar, A S (Oil and Natural Gas Corporation Ltd) | Deuri, BUDHIN (Oil and Natural Gas Corporation Ltd)
In an offshore field, mitigation of H2S from natural gas itself is a big challenge. A situation where high H2S present in well fluid increases the challenges several fold to sweet both processed oil and gas. In a wellhead platform/remote location where manual intervention requirement is minimal, conventional process has several limitation such as space availability, load on structure, frequent monitoring etc., hence may not be suitable for mitigation of H2S from processed gas and oil.
In this work, an approach is adopted for sweetening of sour gas and sour crude in an optimum way, keeping offshore constraints in mind and without usage of rotating equipment's. An integrated simulation model is developed in Aspen HYSYS process simulator wherein well fluid from well manifold is processed in three phase oil and gas separator. The gas liberated from the separator is first sweetened in adsorption columns considering three bed systems unlike general usage of two. The oil is sweetened in an envisaged stripper column utilizing sweet gas from adsorption column as stripping gas. In this work, a three bed adsorption column is envisaged wherein 1st two column in used for sweetening of gas liberated from separator which consists of around 7500ppm H2S. Sour oil from the separator which contains around 2000 ppm of dissolved H2S is processed in a stripper column for mitigation of H2S dissolved in the oil. Sweet gas liberated from 1st two column of adsorber bed is used as stripping gas for oil sweetening. H2S liberated from stripper column is routed to the 3rd column for sweetening. After this gas from all the adsorber column is combined and routed to process platform along with the sweet oil. Analysis reveals that, this scheme can sweeten altogether both oil and gas to the desired H2S level without the need of any rotating equipment's and must be a suitable for remote location.
A holistic approach was taken for sweetening of oil and gas without the need of any rotating equipment's, & any chemicals, unlike the conventional method and hence can be suitably adopted for an offshore environment or at remote location where requirement of manual intervention is bare minimum.
Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.
One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.
It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.
This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
Drilling operations are faced with conditions of subsurface uncertainty with unexpected drilling hazard potential. Operation is done in 24 hours a day continuously, until drilling is declared complete. The consequence of this work environment is the potential for high work accident, one of which is caused by situational conditions in the field that allow the communication limitations in clear and detailed.
Such conditions may include high-noise working conditions, limited visibility due to weather hazards (rain, fog, dark / night), and sour gas exposure. In this condition, often verbal communication is followed by non verbal communication, either in the form of the use of horns (morse), flag raising (semaphore) and limb movements. Non-verbal communication will be more urgent if the drilling operation conditions in emergency conditions, such as the occurrence of kick, blowout and exposure to sour gases. Non-verbal communication occasionally used in any drilling site does not have standardization, thus increasing the potential for communication errors.
Methods Non-verbal instructions intended in this paper is a sign language that serves as a medium for delivering work orders (instructions). This non verbal instruction uses one limb, represented by at least 2 limb movements in at least 2 stages of movement, to interpret a command or work instruction. If less than 2 movements or less than 1 stage of movement, then the movement of the body may have meaning, but can not be implemented because the instructions are not complete
With the invention, paper and efforts of this standardization, the communication process and the delivery of orders in both normal and emergency conditions at the drilling sites can be carried out in a structured, standardized, clear, detailed and widely applicable manner. The instruction method in the form of non-verbal codes is named: NS Blind Code Drilling, which has been registered since December 2014 to the Directorate General of Intellectual Property Rights and is in process related to the patent application.