Rishabh Uniyal

Abstract This paper aims to elucidate the various benefits of continuous dosage of suitable scale inhibitor into the reservoir through injection water to prevent down hole deposition of scale in offshore development wells. Various consequences of inadequate chemical dosing have been deliberated. Detailed description of methodology adopted for chemical selection has also been elaborated in the paper. Most oilfields in India's Western Offshore region are brown/matured fields which have been in production for more than three decades. Reservoir pressure management system, which includes seawater injection as one of the primary techniques, has been in place since the 1990s. Seawater has a high concentration of inorganic minerals which are not always compatible with formation water. The chemical injection plan, part of the larger seawater injection system, had initially included provision for anti-scalant injection. The same was however discontinued at a later stage based on a separate study. The study took into account the water chemistry at the time (late 1990s) and stated that the water was unlikely to scale in the near future. Two decades on and inorganic scaling has plagued majority of the development wells in the field. This has led to a rampant rise in the requirement of scale removal jobs in the field over the past decade or so. Scale prevention is a superior and economical alternative to scale removal due to reduced consumption of chemicals and prolonged life. As part of this study, the feasibility of continuous injection of a suitable scale inhibitor into the reservoir has been re-examined and subsequently, extensive laboratory experiments were performed to identify suitable chemicals. Additionally, the repercussions of not dosing a suitable chemical/ inadequate dosage have been discussed. As part of the study, injection water samples were collected from strategic locations all over the western offshore injection water network and analysed for scaling tendencies. The results show beyond doubt that decades of production has led to injection water breakthrough/encroachment and with it, the problem of inorganic scaling. Based on a comprehensive literature review and market scouting, six inhibitors were evaluated for their inhibition efficiency, thermal stability and compatibility with the rock formation through laboratory experiments under simulated reservoir conditions. Based on the results, chemical X was identified as being most suitable for continuous injection into the reservoir to combat scaling issues in both injection and development wells. The study discusses the various pros and cons of continuous scale inhibitor dosing thru seawater injection for an offshore carbonate reservoir. It analyses the feasibility of starting afresh a scale inhibitor injection program, after the field has been in production for more than 3 decades. The entire chemical selection process has also been detailed.

Abstract Field X is situated at a water depth of 90 meters in the western continental shelf at a distance of 200 Kilometers from Mumbai. It is one of the few fields in the world operating entirely on Electric Submersible Pumps with 36 wells in 5 wellhead platforms producing 62907 barrels of liquid per day with an average water cut of 68%. The performance of ESPs is being continuously monitored in the field. With continuous improvement, the run life of ESPs has increased from a few months to an average of 3 years. Despite the improvement in the run life, unexpected failures still occur from time to time. These unanticipated ESP failures cause substantial production deferment leading to considerable losses in terms of revenue and resources. This paper presents the findings of an Artificial Intelligence based model developed for failure prediction of ESPs aiming to minimize the unexpected production loss for Field X. From the historical data obtained, 47 instances of pump failure have been identified. One of the challenges encountered during Data Exploration was missing data which in many cases was due to downhole sensor failure before the pump failure. The missing values have been inferred and imputed from the known available parameters for each pump. Various machine learning algorithms including Random Forest Regressor, Xgboost Regression, Copula-based Outlier Detection, Scalable Unsupervised Outlier Detection and Long Short Term Memory (LSTM) Autoencoder have been applied on these failure instances to develop a model for predicting the run lives of ESPs. Out of all the methods, LSTM Autoencoder model has been found to be the best suited model for anomaly detection before failure of ESPs. Autoencoders learn patterns in data over long sequences which makes them suitable for anomaly detection before the actual pump failure. The pattern recognition algorithms of Autoencoders have been able to predict the anomaly at approximately ~60 days before failure in a number of pump failure instances. The paper discusses a proactive approach by building a predictive model for estimating ESP lifespan based on machine learning algorithms. The model's predictive accuracy can be improved over time by adding information and further improving the model components.

Abstract Field Alpha is situated about 200 km West of Mumbai city in a Deep Continental Shelf at the water depth of 85 - 90 m. The existing facilities consists of 5 Well Head Platforms (WHP) connected to FPSO through a subsea PLEM and riser system. A total of 36 wells from 5 well head platforms in the field are producing 61348 blpd with an average water cut of 68%. All these 36 wells are producing through Electric Submersible Pump which is one of the most effective and economical means of lifting large volumes of liquid. The current paper is an attempt to address various issues pertaining to Electrical Submersible Pumps in the offshore field using well wise Nodal Analysis and Integrated Production Modelling. In the field under study, as the production volumes per well are high, failure of even one ESP leads to substantial production loss till the system is replaced by work over operation. Failure in the ESP system generally occurs due to one or a combination of issues related to reservoir inflow, fluid properties, design, completion, electrical components and experience of manpower. On the basis of system analysis, requisite optimization/ intervention measures proposed to improve performance of ESPs along with network debottlenecking results have been discussed in the paper. As per the analysis, scope exists in 7 wells for production enhancement. The envisaged incremental production from these wells has been found to be 1653 blpd considering current reservoir pressure and water cut. In 7 wells, ESPs have been found to be operating either in upthrust or are tending towards upthrust. These wells have potential to produce more but due to limitations of the existing pump capacities, the maximum drawdown is restricted. In 6 wells, ESPs have been found to be operating in downthrust. These wells have separately been assessed for wellbore performance. Additionally, Integrated Production Modelling indicated that the node pressure at each Well Head Platform are within the ESP design pressure limits. On the basis of the study, few of the recommended measures have already been implemented in the field and have resulted in a liquid gain of 335 blpd (139 bopd).

Abstract The paper aims to elucidate the process undertaken to identify suitable inhibiting chemical to prevent down hole deposition of scale in ONGC western offshore wells by means of a squeeze job. Detailed description of methodology adopted for chemical selection has been elaborated in the paper. Most fields in ONGC's Western Offshore region are brown/matured fields with depleted reservoirs pressures. Seawater injection is one of the primary techniques used to combat depleting reservoir pressure. This has led to rampant escalation in scaling issues in offshore limestone reservoirs and subsequently, the frequency of scale removal jobs has also increased exponentially over the past two decades. Scale prevention is a superior and economical alternative to scale removal due to lesser consumption of chemicals and prolonged life. As part of this study, the feasibility of carrying out Scale Inhibitor Squeeze Jobs in ONGC offshore wells was examined and subsequently, extensive laboratory experiments were performed to identify suitable chemicals. The experiments included inhibition efficiency tests, thermal stability tests and extended core flow studies (adsorption and desorption methods) to verify chemical compatibility with core sample of a number of generic and vendor based chemicals under simulated reservoir conditions. After a comprehensive literature review and market scouting, six Scale Inhibitors were shortlisted and evaluated for their inhibition efficiency, thermal stability and compatibility with the rock formation through laboratory experiments. After extensive testing, Chemical X was identified as being most suitable for scale squeeze job in carbonate formations having temperatures up to 110° Celsius (230° F) and was also compatible with the formation. The adsorption and desorption isotherms respectively demonstrated sufficient chemical retention in the core and slow elution in the discharge. The measured Scale Inhibitor concentration was found to be greater than the Minimum Inhibitor Concentration (MIC) required for scale prevention. This indicated that any potential squeeze job would likely have a reasonable expected life. The study explores the possibility of carrying out a first ever scale squeeze job in ONGC Western Offshore reservoirs particularly with high temperature application. Core flow experiments were performed using scale inhibitor chemical to derive adsorption and desorption isotherms used to prepare customized job plans.

Abstract Multiple ESP wells in an Indian Offshore Carbonate reservoir were afflicted with inorganic scale deposition chronically. Analysis of recovered deposit samples was carried out and the root cause of deposition established. This was followed by successfully carrying out remedial operations for scale removal and prevention. The experience gained from the same has been elaborated in the paper. Inorganic scale deposition in Electrical Submersible Pumps has been a big cause of concern in many wells of a carbonate reservoir in Indian Offshore. Scale deposition in ESPs causes decrease in pump efficiency and sometimes, complete choking and ultimate failure. As part of this study, a detailed Compositional Analysis of recovered samples retrieved from inside the ESP was carried out. Based on the analysis, custom job plans were formulated to clear the scale from within the ESPs and its vicinity. This was followed by a continuous inhibitor injection program from a downhole chemical injection mandrel after the selection of the appropriate chemical. The results of the compositional analysis of the recovered debris showed that despite the well operating in a carbonate reservoir, the majority of the sample was acid-insoluble sulphate scale. Further probing elucidated the fact that multiple acid washes had been performed in the well, which while dissolving the carbonates, left behind insoluble sulphates as residual scale. The operating conditions inside the pump were also especially conducive for sulphate deposition. As such, tailored job plans consisting of a formulation of a chelating agent in an alkaline solution were designed and executed. Implementation of the job plans resulted in significant oil gain from the affected wells and the continuous inhibitor injection has further improved the efficiency of the ESPs and reduced the frequency of cleaning jobs required. The paper aims at providing an insight into inorganic scale deposition in ESPs. After analysing the scaling problem and establishing the root cause, mitigating measures have been devised and implemented. The paper provides a holistic approach towards tackling the problem of existing inorganic scale and preventing future deposition from taking place. The experiences gained during the entire exercise have been deliberated in the paper.

Abstract Analysis of recovered scale samples deposited within Electrical Submersible Pumps in offshore wells was carried out. The primary objective includes the identification of root cause of deposition and suggesting remedial measures for removal and prevention. Many wells in an offshore field in ONGC are facing an acute problem of decrease in pump efficiency and ultimate failure of Electrical Submersible Pumps due to deposition of inorganic scale. The methodology for carrying out the study consists of a detailed Compositional Analysis of a sample of scale retrieved from inside the ESP of one of the affected wells. Additionally, X-Ray Diffraction analysis of the debris and compositional analysis of produced water sample from the same well were also carried out. The results of the experiments were corroborated by software simulation in Scale Prediction Software. Experiments were also carried out to identify a suitable inhibitor which could operate at high bottom hole temperatures experienced in the affected wells for preventing any future deposition. Based on the compositional analysis of the scale and simulation runs using the produced water analysis, it was established that deposition of hard, adherent sulphate scale was the primary reason behind the choking and subsequent failure of the ESPs. In-situ conditions leading to deposition of the scale including variations in the operating environments and the effect of pump sizing have also been discussed. The paper analyses the problem of inorganic scale deposition in offshore ESPs of ONGC utilising actual scale samples retrieved while dismantling the pump. An attempt has been made to provide an insight into the driving mechanism behind deposition inside the pump and various factors leading to it. The paper also details extensive lab experiments carried out to identify suitable inhibitors for high temperature application.

Abstract 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.

This workshop aimed at producing an optimized photon source concept with potential increase of scientific output at Jefferson Lab, and at refining the science for hadron physics experiments benefitting from such a high-intensity photon source. The workshop brought together the communities directly using such sources for photo-production experiments, or for conversion into $K_L$ beams. The combination of high precision calorimetry and high intensity photon sources greatly enhances scientific benefit to (deep) exclusive processes like wide-angle and time-like Compton scattering. Potential prospects of such a high-intensity source with modern polarized targets were also discussed. The availability of $K_L$ beams would open new avenues for hadron spectroscopy, for example for the investigation of "missing" hyperon resonances, with potential impact on QCD thermodynamics and on freeze-out both in heavy ion collisions and in the early universe.

The atomic bond and molecular polarizabilities of some fullerenes and aromatic hydrocarbons have been calculated using variational method and delta-function electronic wave functions. The geometries of C 6 0 , C 7 0 and the two stable froms of C 8 4 have also been optimised.

The polarizabilities of some ferrocene derivatives have been calculated using a new empirical approach based on the square of the sum of the atomic hybrid components (τ A ) as given by the relation a(ahc) = 4/N[Σ A τ A ] 2 (A 3 ), where the summation proceeds over all atoms A = 1, 2, 3..., and N is the total number of electrons in the molecule. Scales have been presented, where the derivatives are classified in order of their polarization properties. Common trends and patterns of behaviour are recognized and discussed.

Abstract Analysis of tubing failure of SRP wells with respect to uniform corrosion, pitting and mechanical abrasion has been carried out. The primary objective includes the identification of root cause of failure and suggesting alternate metallurgy. Many wells in an onshore field in ONGC were facing the acute problem of general corrosion, pitting and rod-tubing wear. The methodology for carrying out the study consists of a Failure Analysis of a retrieved sample of the failed tubing from one of the affected wells. This included a thorough visual inspection, Scanning Electron Microscope analysis and X-Ray Diffraction analysis. The results of these tests were backed up by software simulation in Honeywell Predict. Metallurgy selection involved multiple exhaustive simulation runs in Honeywell Software Socrates which was corroborated by relevant oilfield standards as well as literature available on the subject matter. Based on the failure analysis and simulation runs, it was concluded that besides the issue of uniform corrosion and pitting, many of the affected wells are also facing the problem of tubing failures due to abrasion and mechanical wear. It is pertinent to note that the major contributor of the frequent tubing failures in the candidate wells selected for the study were pitting and corrosion. Nevertheless, Abrasion always remains a key threat to the tubing string integrity in rod-pump wells. Therefore, the existing tubing metallurgy of N-80 grade Carbon Steel was deemed inadequate in the absence of reliable corrosion inhibitor continuous dosing facilities. A tubing metallurgy that takes care of both pitting corrosion as well as abrasion and mechanical wear was sought. UNS 41426/41427 or the modified version of 13 Chrome, commercia lly known as Super Martensitic 13 Chrome, are available in 95 ksi and 110 ksi grades. These grades have a maximum hardness of 28-32 HRC which is substantially high compared to L-80 13 Cr (maximum 23 HRC). Also, as this alloy has 4-6% Nickel, it provides added protection against uniform corrosion as well as pitting and hence was recommended. The paper specifically analyses tubing failure in Sucker rod-pump wells due to corrosion, pitting and abrasion. After exploring various viable options, adequate tubing metallurgy has been recommended that should take care of corrosion, pitting as well as mechanical wear problems.

Abstract The paper aims to discuss various issues pertaining to gas lift system and instabilities in low producer wells along with the necessary measures for addressing those issues. The effect of various parameters such as tubing size, gas injection rate, multi-porting and gas lift valve port diameter on the performance analysis of integrated gas lift system along with the flow stability have been discussed in the paper. Field X is one of the matured offshore fields in India which has been producing for over 40 years. It is a multi-pay, heterogeneous and complex reservoir. The field is producing through six Process Complexes and more than 90% of the wells are operating on gas lift. As most of the producing wells in the field are operating on gas lift, continuous performance analysis of gas lift to optimize production is imperative to enhance or sustain production. 121 Oil wells and 7 Gas wells are producing through 18 Wellhead platforms to complex X1 of the field X. Out of these 121 oil wells, 5 are producing on self and remaining 116 with gas lift. In this paper, performance analysis of these 116 flowing gas lift wells, carried out to identify various problems which leads to sub-optimal production such as inadequate gas injection, multi-porting, CV choking, faulty GLVs etc. has been discussed. On the basis of simulation studies and analysis of findings, requisite optimization/ intervention measures proposed to improve performance of the wells have been brought out in the paper. The recommended measures predicted the liquid gain of about 1570 barrels per day (518 barrels of oil per day) and an injection gas savings in the region of about 28 million SCFD. Further, the nodal analysis carried out indicates that the aforementioned gas injection saving of 28 million SCFD would facilitate in minimizing the back pressure in the flow line network and is likely to result in an additional production gain of 350 barrels of liquid per day (65 barrels of oil per day) which adds up to a total gain of 1920 barrels of liquid per day (583 barrels of oil per day). Additionally, system/ nodal analysis has also been carried out for optimal gas allocation in the field through Integrated Production Modelling. The analysis brings out a reduction in gas injection by 46 million SCFD with likely incremental oil gain of ~100 barrels of oil per day.