bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Artificial Neural Network and Object-based Modelling for Enhancement History Matching in a Fluvial Channel Sandstone Reservoir
Authors: Vo Thanh Hung , Sugai Yuichi , Nguele Ronald , Sasaki Kyuro 
Published: October 2019

Abstract
Modelling accurately lithofacies and petrophysical properties is an important yet challenging process especially at the beginning of exploration and production from hydrocarbon reservoirs. However, the limited amount of well data and core data are the main issues facing conventional modelling processes. In this paper, Artificial Neural Network (ANN), Sequential Gaussian Simulation (SGS), Co-kriging and object-based modelling (OBM) were integrated as the enhancement framework for lithofacies and petrophysical properties modelling in the fluvial channel sandstone reservoir.
In the OBM, multiple fluvial channels were generated in the lithofacies model. The result of this model represented all the characteristic of the fluvial channel reservoir. The model was then distributed with channels, crevasse, and leeves depositional facies with background shale. Multiple geological realizations were made and cross-validation to select the most suitable lithofacies distribution. This model was cross-validated by modelling the porosity and permeability properties using Sequential Gaussian Simulation.
Thereafter, the modelling process continued with Artificial Neural Network. Petrophysical properties (mainly porosity and permeability) were predicted by training various seismic attributes and well log data using the ANN. Applying the co-kriging algorithm, the predicted ANN model was integrated with OBM simulated lithofacies model to preserve the fluvial features of the geological system. To achieve full field history matching, the final geological model was upscaled to serve as input data in dynamic history matching.
An excellent and nearly perfect history matching with a least mismatch was obtained between the measurement and simulated bottom hole pressure from well test and production history. The results indicated that an efficient integrated workflow of ANN and other geostatistical approaches are imperative to attaining an excellent history matching.
Key Parameter of Successful Matrix Acidizing to Combat Fines Migration in Gravel Pack Wells
Authors: Primasari Indah , Abidiy Izzad , Ismail Taufiq , Wijaya Geraldie Lukman , Hadi Aen Nuril , Yasa I Made , Luiren Bernardinus Andrie , Fuad Muhammad , Merati Putu Astari , Jayadi Agus , Akbari Aulia 
Published: October 2019

Abstract
In common practice, gravel pack completion is beneficial as sand control in a typical unconsolidated sandstone reservoir. However, with poorly sorted sand grains, fines migrate and deposit at the gravel-pack matrix, causing permeability reduction and hence, decreasing well productivity. Matrix stimulation has been proven to remove the fines blocking the pore throat. The desired solution has been carefully selected to have prolonged well production. Organic clay acid is chosen for to its ability to have deeper penetration and to create a thin coating on the pore surface to prevent fines migration. Laboratory testing and field application were performed in parallel. A core flood test with reservoir core samples showed a result of 111% regained permeability. Ten treatments were conducted and showed good results. The productivity index increases 10 times on average. From those experiences, a benchmark was identified, which factor determines the success of a treatment. This paper presents the project preparation and execution, key reasons to success, and the way forward.
Approach to Establish Well Network Debottlenecking Using Surface Well Testing & Pumping Spreads in a Complex Network System in Mature Fields, Rajasthan, India
Authors: Pandey Arpita , Ranjan Amit , Kumar Manish , Dangwal Gaurav , Maniar Chintan , Raju Pruthvi , Agarwal Paresh , Nagar Ankesh 
Published: October 2019

Abstract
Cairn Oil & Gas in Joint Venture with ONGC, is the operator of contract area RJ-ON-90/1 in the state of Rajasthan, North West India. MBA fields (Mangala, Bhagyam and Aishwarya Field) comprise of more than 565 wells. Produced liquid from these wells is transferred to Mangala Processing terminal (MPT) where liquid from each of these wells is collected and processed. MPT processes ~11,00,000 BLPD and separated water is re-used for water injection for pressure maintenance and power fluid for jet pump artificial lift. This requires stringent separation procedures to maintain injection water quality.
With the terminal operating at the limit of its processing capacity and high field water cut, maintaining oil production with high liquid handling posed a big challenge.
The objective was to prove the concept of addressing liquid handling constraint and optimizing oil production by utilizing standalone separation and pumping systems. It was anticipated that bottlenecking in the lines was causing high backpressure on the wells which led to substantial decrease in well liquid production. A network model was created which confirmed this. This paper describes the approach used to establish a standalone set-up for header pressure reduction and increased liquid handling using surface well test and pumping facilities.
The network model indicated that for an increase of 1 bar pressure in production header, there was a substantial loss in oil production from each network of MBA field. For example in Mangala Cluster A, this resulted in ~ 400 BOPD of loss in oil production.
Later an idea was developed to take out ~10,000 BPD liquid from production header line of a network and the same was separated using standalone well test & pumping spread. It was planned to pump oil back into production header and use the produced water for Jet Pumping application and remaining water to be pumped in nearby injector. The entire operation was planned with 2 standalone surface well test spread and pumping units.
Post achieving success in Mangala field the same idea was implemented in Aishwarya field where the main objective was to knock off the gas from the system along with liquid reduction from the production header which ultimately reduced the back pressure on each of the well in the pad.
Dynamometer Card Classification Using Case-Based Reasoning for Rod Pump Failure Identification
Authors: Wibawa Ramdhan , Handjoyo Teguh , Prasetyo Joko , Purba Monas , Wilantara Dedi , Dongoran Japet , Gunawan Gunawan , Negara Ari 
Published: October 2019

Abstract
Sucker Rod Pumps (SRP) have been extensively utilized in the Duri field Heavy Oil Operations Unit (HOOU) for more than 6000 production wells. Approximately 2000 of these wells are equipped with dynamometer online that generates a daily dynamometer card (DC). Historically, the pump cards evaluation has led to the identification of several mechanical pump issues such as a traveling valve and standing valve leak that directly impact production.
One step of the traditional process to identification of rod pump failure is based on a manual pump card shape analysis performed for individual wells by different engineers throughout production history. To improve efficiency and reliability of shape analysis, Artificial Intelligence-based data analysis has been recently integrated in the oil and gas industry. This article proposes an approach to pump card classification, developed by the Integrated Optimization Decision Support Center, using a modified Case-Based Reasoning or computer reasoning by analogy approach where new problems are solved by comparison to analogous problems solved in the past.
The proposed methodology begins with definition of a reference DC for every known type of mechanical failure. The reference cards define the analogy set. Actual pump cards are then normalized and compared for similarity against each reference card or analogy using Euclidean distance measure between the actual and reference cards. For each actual pump card, the output of this approach is a set of similarity scores which indicate the pump failure type corresponding to references card shape, if any. The analysis is enhanced through the addition of rules based on pump operational parameters that result in specific pump failure signals. The methodology has been verified against DC evaluations from Subject Matter Experts (SME) and is demonstrated to provide robust pump failure signals more efficiently than by manual interpretation of DC for a series of individual wells.
Composition Based Gas Optimisation through Integration of Oil and Gas Field to High Grade Project Economics: A Case Study
Authors: Tan Kok Liang , Bt Beserdin Nur Hafizah , Bansal Rajive 
Published: October 2019

Abstract
With the increasing energy demand and call for cleaner energy, industry has ventured out for challenging environment such as deepwater and unconventional natural gas resources. While new development is necessary, improvement in gas supply can also be achieved by relooking into the current system. Currently, associated gas produced from oil well are mainly used in petroleum operations, while the remaining gas are either flared or vented to the atmosphere. Inefficient usage of associated gas which has high heating value impose a great value leakage to the company.
This paper introduces a new concept that demonstrates more efficient usage and monetization of gas by utilizing associated gas and non associated gas based on its composition instead of volume and sales agreement. The value addition of this new concept was evaluated across the process chain from the upstream operator, host authority, to the downstream plant processing and end product at customer level, using a case study at Field A and Field B.
Field A is a brownfield which utilizes produced associated gas for petroleum operations including gas reinjection. Field B is a non-associated gas green field which is tied in to Field A’s processing facilities prior to gas export. Both gas from field A and field B were evaluated based on their gas composition, gross heating value and customer requirement to determine the best option of gas utilization to maximize its value. Feasibility study was carried out to ensure the practicality of the job execution and at the same time commit to the legal and sales requirements.
Field A and B belongs to the same PSC, and gas sales are purely based on the heating value and contractual volume requirement. Hence, Field B lower heat value gas can be used for injection provided that the similar volume was replaced for sales. The gas swapping for optimization can be conducted through simple flowline modification with minimal cost. A portion of gas from field B will be directed for gas reinjection at field A, while the associated gas at field A originally intended for injection will be utilized for sales. Injecting gas with leaner hydrocarbon composition will not hinder the oil recovery efficiency of field A. However, gas sales using associated gas from field A allow additional 11% profit gain for the operator from existing scenario. The products of processing the swapped associated gas will reap more profits to the downstream sector, as the gas has higher ethane, propane, and butane molecules.
In the current situation, existing fields have always considered gas utilization individually. There is potential for all fields to utilize gas more effectively to increase the economic value of the field and downstream facilities.
Complex Approach to Optimize Completion and Well Placement Strategy for Unconventional Gas Wells: Marcellus Study
Authors: Nikolaeva Alfiya , Boyer Charles M. , Xu Lili , Arroyo Kenneth 
Published: October 2019

Abstract
Even with the current development of unconventional reservoirs in the United States, where tens of thousands of wells have been drilled and completed, there is not enough understanding of the production and successful completion drivers in unconventional plays.
The Marcellus shale is a naturally fractured formation, and it is vital to account for the natural fractures during a simulation study. A discrete fracture network (DFN) model and a 3D mechanical earth model (3D MEM) were created and used to determine the complexity of the hydraulic fracture geometry. The microseismic data obtained during the hydraulic fracture simulations served to constrain the hydraulic fracture footprint.
The proposed workflow uses unconventional fracture modeling (UFM) to predict the propagation of complex hydraulic fracture networks with pre-existing natural fractures and model the stress shadow effect and the lamination effect considering different proppant placement by type within the fracture. Propped and unpropped fracture half-lengths obtained during history matching provide calibration for the UFM. Based on the calibrated model, an analysis of the current perforation efficiency was performed, which showed that almost half of the perforations do not contribute to the production. Optimization of well spacing and cluster spacing was performed on a two-well pad to account for well interference such as fracture hits, stress shadow, and depletion after 30 years of production. The recommended well spacing and completion design improved production by up to 20% per well compared to the initial development plan.
The complex approach is becoming a new norm for the successful development of unconventional reservoirs because simple analytical models cannot address well interference issues and account for heterogeneity in the rock properties. The presented workflow can be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus to help achieve maximum recovery.
Gas Lift Robbing Prevention in Dual String Completion using Production Pressure Operating Valve
Authors: Sajjad Farasdaq Muchibbus , Sastradinata Khairullah , Rahmawati Silvya Dewi , Mansur Achmad , Wirawan Alvin , Mujib Ecep 
Published: October 2019

Abstract
Common problem for dual string completion gas lift well is a misallocation problem called as a gas lift robbing, where the gas tends to be injected uncontrollably to one of the tubings. Consequently, both oil production of the strings drops since the injected gas does not meet the optimum allocation. To solve this, engineers need to shut in one of the strings using wireline which is time-consuming and uneconomic. Therefore, the objective of this paper is to introduce the modification of dual string gas lift design that can economically prevent gas lift robbing problem in the well during the production time.
This finding occurred in Indonesia, Offshore North West Java field, where the orifice is preferably used as the operating valve. However, Production Pressure Operating (PPO) valve is then used to replace the orifice function to overcome the problem. The methodology starts with well selection based on the possibility to perform the new design. Then, the static bottom-hole pressure test applied in each zone to obtain an appropriate pressure. Lastly, PPO valve’s Pressure Test Rack Opening (PTRO) will be designed based on the measured bottom-hole pressure to be applied to one of the selected string to prevent the gas lift robbing.
The force balance is then calculated, and the PPO valve is set to the short string with the Pressure Test Rack Opening (PTRO) 585 psig at 80°F. The oil production in the robbing well observed to increase by 45% and achieved a sustainable production after replacing its orifice with the PPO valve. Also, The PPO valve will prevent the gas robs to the selected string as it will close automatically when its tubing pressure drops bellow PTRO. Hence, the wireline activity is now unnecessary because the PPO valve will be closed automatically when the gas lift robbing occurs again.
The use of PPO valve is commonly suitable as an unloader in low availability of Casing Head Pressure (CHP) and high reservoir pressure. By this study, PPO valve has been successfully replaced orifice function with high CHP and low reservoir pressure to prevent the gas lift robbing problem effectively in Offshore North West Java field.
Holistic Digital Transformation – Key Enabler to Enhance Productivity, Flexibility and Reliability for an E&P Company
Authors: Deka Mousumi , Roychoudhury Atindra 
Published: October 2019

Abstract
The upstream E&P industry encompasses diverse range of activities. The core activities may be broadly classified as G&G, Drilling, Production and Transportation and non-core activities supporting efficient execution of core activities and the business as a whole may be classified as Finance, Contracts and Purchase Management, HRM and Engineering services. E&P industry is one of the earliest adopters of digital technologies in its operations to efficiently transform complex reservoirs into revenues.
Oil India Limited (OIL), the 2nd largest national E&P Company of India too adopted digital technology in its G&G activities encompassing Seismic data acquisition, processing, interpretation and logging in 1970s. It was followed by use of high end workstations for reservoir studies & modelling in 80's. Over the years, OIL deployed number of digital interventions in both core and non-core activities. However, like other E&P companies, induction of digital technology is slow in core activities like Drilling and Production. As far as non-core activities are concerned, advanced digitisation methodology adopted in the area helped OIL in enhancing efficiency and ease of data access in B2B, B2C relationship.
Crude oil and Natural Gas price volatility demands that E&P organizations to be more agile and competitive. Thus there is need of collaborative workplace with real time data analysis and efficient decision making facility. As a solution, number of intelligent IT technologies in the form of IoT, Data Analytics, Machine learning, Artificial Intelligence, Augmented Reality etc. are emerging at an affordable cost. Adopting these technologies in a holistic way integrating all core and non-core activities of an E&P industry can fulfil the need of above desired solution enhancing productivity, flexibility, reliability and RoI.
Believing "Holistic Digital Transformation" is the success mantra to become more agile and competitive, OIL has embarked in the process of implementing new digital technologies integrating all its core and non-core activities. The paper describes OIL's methodology towards holistic digital transformation.
Water Injection Optimisation for Matured Waterflood Reservoir: A Case Study for Value Creation from Improved Production Performance and Cost Savings
Authors: Md Yunos Khairil Anuar , Mansour El Harith Mohammed 
Published: October 2019

Abstract
This paper will highlight the study, implementation and results of water injection optimization program in a matured waterflood reservoir prior to the implementation EOR IWAG tertiary recovery. The scope included analytical understanding of current reservoir condition, reservoir simulation study for various injection proposals, historical injection facilities performance and the optimization/remediation proposal to increase WIM (Water Injection Module) uptime, and reservoir surveillance requirement to ensure the water injection optimization program meet its objectives.
Low current offtake rate in the reservoir, low WIM uptime, high cum. VRR and an imbalance in the reservoir pressure between the Eastern and Western flanks of the reservoir necessitated a study on the WIM program/schedule to optimize the injection by redistributing the injection volume between the Eastern and Western injectors and identify opportunities for cost saving through WIM shut-off. A history matched model was used to evaluate different injection scenarios. Collaboration between Subsurface and Surface Facilities Team enabled a coherent plan for periodical WIM shut-off and maintenance activities to be designed in order to deliver higher WIM uptime.
The proposals for the injection optimization program were: Apply ‘1 Month Off - 2 Months On’ Injection Cycle, starting April 2017Increase avg. water injection target to 15 -20 kbwpd as per full WIM capacityRe-balance the injection volume between Eastern and Western injectors by ratio of 3:1Maintain WIM/Injection uptime consistently above 76% during injection months
The results from the optimization exercise (May 2017 - December 2017) were encouraging and better than expected from simulation run. Production decline from producing well was successfully arrested with cum. oil gain from the period totaling approximately 18 kbbls (50 bopd annualized). The reservoir pressure in the Eastern flank was increased to reach the level similar with the Western flank. The value creation from additional production gain and cost savings of WIM shut-off was around USD 1.4 MM.
It can be safely concluded that the injection optimization plan has successfully achieved its objectives.
The novel idea and approach from this exercise was the demonstration of how a simple understanding of a reservoir and its associated surface injection performance can provide an opportunity for a quick and simple optimization plan to be implemented to improve the sweep efficiency of the injection by targeting the unswept/bypassed oil and subsequently increase the oil production from producing well(s).
History Match Process Optimizer - HMPO
Authors: Ghamdi Amell , Oluwa Jubril 
Published: October 2019

Abstract
This paper presents an automated method to speed-up the process of history-matching simulation models. A new tool "History Match Process Optimizer– HMPO" was developed to allow local modification of simulation model property arrays around any given well type. Deployment of this tool significantly improved the history-match process of a reservoir simulation model containing a high number of wellbores and a saving of 140 man-hours was achieved.
The tool was developed in LINUX environment and adapted to an in-house developed state-of-the-art reservoir simulator, GigaPOWERS (Dogru et al. 2008, 2009, 2011). The tool has an automated workflow that uses the model perforation file as an input to generate the property modifier file; the perforation file contains all completed wellbores along with their perforated cells. Additional input includes specifying what model property array would be modified around the wellbore (transmissibility, permeability, porosity, fluid contacts, etc.), and number of cells to be modified in 3D directions.
Application of this tool was done on a simulation model as part of the history-match process, 65% of the wells are horizontal or multilaterals. Prior to using this tool, difficulties were experienced when attempting to manually perform local history-match modification around each wellbore to mimic hydraulic fracture completion with fractures extending to several cells away from the wellbore, especially in a fine Giga-scale model with a high number of wellbores. The implementation of HMPO allows a quick generation of the modifier files with ability to repeat the process several times until an appropriate local modifier is achieved for all wellbores at the same time. This made the process of generating the modifier file 200 times faster. Hence this tool became a necessity with large complex models built with high resolution, and advanced computational resources.
The novelty of this work is to assess simulation modeling by providing an automated property-array modification around any given wellbore completion in a way that significantly reduces the duration of history- match process. "HMPO" is an internal effort to speed-up and optimize this part of history match process. Therefore, its application to other big reservoir simulation models in the company would add value, improve efficiency of the process, and enhance the quality of results obtained from history-match calibration.