bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Productivity Assessment Using Advanced Formation Evaluation, Image Logs and Formation Testing and Sampling Methods: A Case Study
Authors: Firdaus Iman , Gultom Luhut , Sadat Anwar , Negara I Made , Yusuf Hotma , Harfoushian Jack , Juandi Dedi , Adeyosfi Merza , Sudarwoto Rinaldi , Wibowo Febrian , Herianto Bambang , Hartanto Rudi
Published: October 2019

Saka Indonesia's primary objective of drilling an appraisal well offshore North-East Java was to accurately assess productivity of the three main reservoirs discovered by the exploration well drilled in the Pangkah Block. This paper details the integration of advanced formation evaluation procedures and interpretation of image logs with novel formation testing methods, which were used to plan and optimise drill stem tests (DST) conducted across the three reservoirs.

Deployed on wireline, formation evaluation and electrical borehole image logs were acquired in open hole of the exploration well. Nuclear magnetic resonance (NMR) and image logs were processed simultaneously in near real time to facilitate the planning of the subsequent formation pressure testing and fluid sampling program. Using the recently introduced advanced formation testing technology, reservoir deliverability was accurately established, in addition to characterising fluids insitu and obtaining reservoir fluid samples.

Interpreted results of data acquired on wireline from different logging runs were integrated and consequently used to optimise the well testing program across the intercepted heterogeneous and low permeability limestone reservoirs. In addition to determining porosities, free fluid volumes and the range of permeabilities, Drill Stem Test (DST) zones were confidently defined using the free water levels ascertained by constructed vertical pressure profiles. As a result, DST measurements matched the permeability and productivity estimations across the three pay zones.

The integrated approach of formation evaluation, textural analysis and permeability and productivity measurements enabled the evaluation of three complex limestone reservoirs discovered in this field, which included secondary porosities and interconnected vugs. These results were ultimately verified and confirmed by the well tests conducted across the three reservoirs.
From Data Collection to Data Analytics: How to Successfully Extract Useful Information from Big Data in the Oil & Gas Industry?
Authors: Al-Alwani Mustafa A. , Britt Larry K. , Dunn-Norman Shari , Alkinani Husam H. , Al-Hameedi Abo Taleb , Al-Attar Atheer M. , Alkhamis Mohammed M. , Al-Bazzaz Waleed H.
Published: October 2019

Big data has become a major topic in many industries. Most recently, the oil and gas industry adopted a special interest in data science as a result of the increasing availability of public domains and commercial databases. Utilizing and processing such data can help in making better future decisions. The aim of this work is to provide an example and demonstrate methodologies on how to collect and utilize big data to help in making better future decisions in the oils and gas industry.

After reading a good number of papers and books about the applications of data analysis in the oil and gas industry, in addition to other industries, and given that data analysis is the area of expertise of the authors, this paper was written to demonstrate real examples of data processing and validation workflows. This work is intended to cover the gaps in the literature were many of the publications only discuss the importance of data-driven analytics.

This paper provides an overview of the diverse and bulk data generating sources in the oil and gas industry, starting from the exploration phase to the end of the lifecycle of the well. It provides an example of utilizing a public domain database (FracFocus) and demonstrates a step by step workflow on how to collect and process the data based on the objective of the analytics. Two real examples of descriptive and predictive analytics are also demonstrated in this paper to show the power of having a diverse and multiple resources databases. A framework of data validation and preparation is also shown to illustrate data quality checks combined with best practices of data cleansing and outlier detection methodologies.

This paper provides a clear methodology on how to successfully apply data analysis which can serve as a guide for some future data analysis applications in the oil and gas industry.
Reservoir Performance Benchmarking to Unlock Further Development of Malaysian Oil Fields
Authors: Ranjan Rakesh , Rizal Mas , Soni Sumit , Masoudi Rahim , Souche Laurent
Published: October 2019

As resource owner and enabler, PETRONAS's Malaysia Petroleum Management (MPM) is entrusted to ensure maximizing recovery efforts from more than 1000 oil reservoirs under production in its portfolio. Performance and recovery from oil reservoirs depends on many factors that can be broadly classified into Reservoir Complexity and how the reservoir has been developed and managed. To undertake a development gap analysis and expectation setting the exercise was undertaken to benchmark reservoir performance against reservoirs of similar complexity. The objective was to take the learnings from better performing reservoirs and explore potential replication in poor performing reservoirs of similar complexity. The main challenge was to establish a single term to define Reservoir Complexity. This term should encompass all the factors like geological, petro physical, rock & fluid etc. that could potentially make the reservoir complex and at the same time also decide on the relative weightage of these parameters posing recovery challenges. Data analytics has been used to accomplish this task and the calibration with reference reservoirs has been achieved. This benchmarking tool can help to internally set targets for all fields where the recoveries have been lower than normally observed, help set EUR numbers for green fields and drive additional development strategies to maximize recoveries in existing fields where they are falling short.

When reservoirs of similar complexities are grouped together, they show varying performance indicators viz. recovery factor, decline rates etc. The gap analysis between the reservoirs of similar complexity has helped in identifying poor performing reservoirs and the underlying reasons for underperformance. Learnings from the better performing reservoirs have been incorporated and a detailed action plan has been prepared to improve the performance of these reservoirs. Considering the various ways in which this information can be used, a reservoir complexity benchmark would be a great asset to any major operator or regulator.

The workflow has been developed to calculate complexity based on the parameters that are affecting microscopic displacement efficiency, horizontal displacement efficiency and the vertical displacement efficiency. Data analytics has been used to assign weightages to each component posing recovery challenges and derivation of a single number defining complexity on a scale of 0 to 1. This is major improvement on all previous works of this nature attempted in various parts of the world and provides the user with not only the complexity per se but also its distribution. This benchmarking tool has been used for selected fields and has enabled development gap analysis and helped in initiating course correction to unlock more values from the underperforming reservoirs.
Characterisation of Paraffin Crystals Aggregation Behaviour in Shearing Fields Using Fractal Dimensional Analysis
Authors: Ni Guangyuan , Wang Zhihua , Yang Heng , Li Jiexun , Zhao Xinming , Liu Yang
Published: October 2019

The paraffin crystals can aggregate and precipitate when the oil temperature declines below the wax appearance temperature (WAT) of the waxy crude oil. However, the aggregation behaviour of paraffin crystals during the process of crude oil production and transportation is not well revealed. This study concentrates on using fractal dimensional analysis to elucidate the aggregation behaviour of paraffin crystals in shearing fields. A set of microscopic experiments was recently performed to capture the basic information of the paraffin crystal images in different conditions. A methodology for characterizing paraffin crystal aggregation was then developed, and the blanket algorithm was introduced to compute the fractal dimension of aggregated paraffin crystals. The results indicate that the aggregation behaviour of paraffin crystals is closely related to temperature and shearing experienced by the waxy crude oil. The aggregation behaviour would be intensified with the reduction of temperature and the decrease of shearing effect, and it appears to be a wider fractal dimension distribution at lower temperature when the same shear rate range is employed. The lower fractal dimensions are at high temperature and strong shear action, the weaker nonlinear characteristics of paraffin crystals aggregation structure are, and thus the potential paraffin deposition would be inhibited during waxy crude oil production and transportation. The methodology developed in this study is beneficial to optimize the flow assurance operations in single-phase and multiphase pipeline transportation for waxy crude oils, and the results are expected to lead to a better understanding of paraffin crystallization and deposition mechanism.
Determination of Sand Production Intervals in Unconsolidated Sandstone Reservoirs Using Spectral Acoustic Logging
Authors: Aslanyan Irina , Maslennikova Yulia , Minakhmetova Roza , Aristov Sergey , Sungatullin Lenar , Giniyatullin Artur
Published: October 2019

Solid particles (sand) production in oil and gas wells can significantly affect well productivity. The negative effect can be caused by sanding up of the perforations, tubing and downhole equipment, and abrasive wear of the well completion and surface equipment. The near-wellbore zone can also be damaged. Considering this, it is critically important to be able to identify sand production intervals for the purposes of ensuring sand control and preventing the negative impact of sand production.

The paper presents a new method of locating sand production intervals using spectral acoustic logging tools, which consists of detecting signals generated by solid particles being transported by fluid flow and hitting the acoustic logging tool housing. The next generation spectral acoustic logging technology was used to identify reservoir intervals producing solid particles. The developed method was tested and utilised in a deviated well of one of the large gas fields in South East Asia, where sand production was a serious problem. Well logging operations, including spectral acoustic logging, were performed in two different production regimes. This approach not only demonstrated a good data repeatability, but also helped determine the optimum production regime of the well with sand production being under control. The acoustic logging data was processed by an adaptive recognition algorithm to identify acoustic signals generated by solid particles striking against the tool housing. The method had previously been tested in the lab.

The proposed method of identifying sand production intervals in producing wells makes it possible to locate sand production zones and define a production profile in one logging run. The obtained information was used in planning a remedial job with the objective of isolating sand production intervals in the surveyed well.
A Novel Formula for Estimating Oil Compressibility Below Bubble Point Pressure Using Group Method of Data Handling: A Comparative Approach
Authors: Ayoub Mohammed. A. , Almansour Abdullah. O. , Hassan Anas. M.
Published: October 2019

Oil compressibility (co) plays a vital role in vast aspects ranging from upstream to downstream. For reservoir with pressure below bubble point, the effect of co to the fluid flow is insignificant as it is overshadowed by the presence of large gas compressibility (cg). This study aims to increase the range of applicability and accuracy of the formula used for estimating the co by eliminating the limitations of other existing correlations.

A new formula for the estimation of oil compressibility below bubble point pressure is devised using Group Method Data Handling (GMDH). The approach is a combination of neural networks and some high-level statistical methods which rely on generating simple relations among the input parameters and the dependent parameter. The relations then result in eliminating some parameters with low impact on the output. A series of consecutive layers with the link is generated, and polynomial terms are created. A total number of 322 data points were collected from different sources from literature.

Systematic trend analysis has been conducted to verify that the proposed GMDH model honours the exact physical behaviour. The new proposed model found to follow the correct trend, which implies its soundness. Besides, a comparative study was carried out using the best available correlations to confirm the significance of the results of the oil compressibility prediction using GMDH. Different statistical analyses have been conducted to verify the robustness of the newly developed model. The statistical analyses showed a positive outcome whereby the proposed model obtained the lowest average absolute percentage relative error of 5.17% and the highest correlation coefficient of 96.8%. The best model tested among the other models has five input parameters and an average absolute percentage relative error of 10.955% and a correlation coefficient of 95.6%.

The new approach managed to reduce the curse of dimensionality as four input parameters have found to have a strong dependency on co (solution gas-oil ratio, oil density, reservoir temperature, and reservoir pressure). The new proposed model overcome the limitations described by the locality of some correlations as they depend on data from specific locations.
Data Conditioning and Suitable Data Tolerance for Automated Production Workflows in a Digital Oilfield
Authors: Kok Jason Chin , Saiful Mulok Nurul Nadia
Published: October 2019

Objectives/Scope

In today's Oil and Gas Industry, as we evolve more towards smart fields and integrated operations, the term digital oilfield is being used more often. Many companies implement smart fields where transmitters and gauges are installed in the field along with a Supervisory Control and Data Acquisition (SCADA) system. One common threat faced in a digital oilfield setup is the failure of accurate data transmission. This includes no data transmitted, erroneous/wrong data transmitted, error in the calibration of the field devices, network interruptions, failure of SCADA system etc.

Methods, Procedures, Process

This paper describes the development of a methodology used to overcome the issues of bad data from the field with the usage of data conditioning and also the suitable data tolerance which can be accepted before the system fails. This method uses smart rules and automated data conditioning which involves historical data, data from nearby wells and results from well modeling workflows. When applied in the field, it ensures that the system runs even when not all the required data from the field is acquired for successful workflow execution.

Results, Observations, Conclusions

Implementing data conditioning rules described in the paper improved the accuracy of the workflow from 71% to 98% which represents a huge improvement. The solution was applied in an offshore field. The automated workflows involved in this solution was well status identification, real time production surveillance, real time gas lift optimization, theoretical production rates from well models, well test validation and platform monitoring. As more data becomes unreliable and missing, the confidence level of the results of the workflow also decreases to a certain point where too many required data points are missing or not available and the system would send an alarm and flag the results of the workflow due to unreliable data transmission. This scenario will be seen if there is a complete failure of the SCADA system or severe network interruptions for an extended period of time. The solution and data conditioning methods applied managed to increase production by reducing the amount of time needed to identify wells which quit offshore which reduces deferred production.

Novel/Additive Information

The paper provides a quantitative assessment of the benefits realized by applying the data conditioning and using suitable data tolerance when running workflows used for production surveillance and optimization in a digital oilfield. As we try to achieve higher production rates and greater recovery from the field, more high frequency data is required and the methods described in this paper can be applied to other fields to solve the missing and erroneous data transmission problems.
Utilizing Petrophysical Facies Model in Multi-Layer Pressure Transient Analysis: A Novel Approach
Authors: Kumar Arvind , Ojha Keka , Wydiabhakti Tety Benedicta , Nahar Siddhartha
Published: October 2019

Petrophysical facies modeling plays a key role in reservoir characterization at all levels. At a well level it helps to delineate the layers on basis of certain similar rock physics characteristics, which further can be used in reservoir engineering computations that include layer wise input of properties. At a field level petrophysical facies helps in mapping of reservoir units in a multi-well scenario.

Pressure transient tests are performed to determine the reservoir properties like horizontal permeability (Kh), vertical permeability (Kv), skin, knowledge of reservoir boundaries and understanding the reservoir structure up to a level etc. All these are used in the field development planning (FDP).

Conventionally, in a pressure transient interpretation a reservoir layer is taken as homogenous, i.e., the reservoir properties are taken uniform across the thickness of sand unit. In highly heterogenous reservoirs, this approach may lead to under-estimation or over-estimation of permeabilities, since a homogenous layer doesn't consider the vertical heterogeneity within the layer. Hence, to address the vertical heterogeneity, multi-layer reservoir model is used in pressure transient interpretations. Each of these layers can be treated as a petrophysical facies.

This paper discusses various ways of petrophysical facies modeling and showcases the usage of these layered reservoir models in pressure transient interpretations. The results from both conventional as well as multi-layered model are compared in different type of reservoir sands.

It is observed that a multi-layer reservoir model gives better results for vertical and horizontal permeabilities in a vertically heterogenous reservoir. The degree of layer division defines the vertical resolution or refinement of permeability values. In a homogenous sand unit, the conventional model can be used up to a certain degree of accuracy.
Revolutionary PDC Cutter Design Help Improve Bit Performance in Malay Basin
Authors: Shahrul Amar Muhammad Shafiq , Seow Beng Chai , Za'ba Muhammad afiq , A Razak M Khairol , W Aziz W Nor
Published: October 2019

This paper describes the application of using new 3D shape PDC cutters in XX development wells in offshore Sarawak. Based on historical drilling data from offset wells around the XX Field, multiple bit trips were required on each section from 17-1/2" until 8-1/2" holes. Various bit manufacturers had come up with several bit designs to drill this field. Post-run bit dull reports showing that those bits were worn out due to formation related issues which were suspected due to interbedded soft shale and abrasive sandstone.

One of the greatest challenges that any PDC bit manufacturer encounter today is the combination of crushing (roller cone) and shearing mechanism (PDC) into drilling challenging formation with single drilling trip. Current PDC application into hard rock drilling, where impact damage, heat damage and abrasive wear of PDC cutters limit its performance. XX Field formation profile with interbedded soft shale and abrasive sand make it impossible to predict on ideal bit selection with combining PDC and Roller Cone runs together effectively.

The challenges have led to the development of a new 3D shape PDC cutter tested in XX Field development wells successfully. The client saved multiple trips of PDC bit runs and drilled 50% farther, double rate of penetration (ROP) than the best PDC bit run in the offset wells. The revolutionary bit cutter design works well regardless of any hole size and BHA configuration. This study will present an analysis of the drilling data from the field and provide a detailed description of the bits and cutter design achievement by comparing the performance of both roller-cone and conventional PDC.

The 3D PDC cutter design has generated a stable rotation and reduced vibrations throughout drilling which resulted in improved ROP while extending the bit life at the same time. The new ground-breaking bit cutter design has provided a viable solution to drilling interbedded soft shale, abrasive sandstone with unexpected hard stringers.
Data-Driven Diagnosis for Artificial Lift Pump's Failures
Authors: Ounsakul Thanawit , Rittirong Ake , Kreethapon Thanawee , Toempromraj Wararit , Wejwittayaklung Kittipat , Rangsriwong Phattarakorn
Published: October 2019

Beam pump and ESP are common artificial lift techniques in pumping systems. They are widely used as primary oil recovery methods, but system failures lead to production deferments and increases in operating expenses. Employing decades of our field data, promising data science techniques are discussed here to analyze the factors governing failures in both beam pump and ESP approaches. These data are then applied with machine learning models to predict service life, failure mechanism performance, and production deferments.

The data analytics process begins with data preparation. Field data were extracted, transformed and loaded into a data warehouse for further processing. These data were categorized by failure information, pump configuration, wellbore geometry, and production information. The significance of each parameter causing pump failures was derived using a process called "Attribute Forward Selection (AFS)." Then several machine learning algorithms were implemented and compared with to determine the most appropriate model to predict pump service life. More suitable pump configurations to improve pump service life were conceptually recommended based on the analysis.

Differences in parameter significance was identified by attribute forward selection, and is displayed in a heat map. It was seen that the use of beam pumps in highly tortuous wells received the number one ranking as the main cause of failures whereas sand production was revealed as the most significant parameter relating to ESP failures. Correlations for these parameters were mapped by machine learning algorithms, resulting in multivariate failure prediction models (i.e. involving more than one parameter at a time) to predict the service life of beam pump and ESP systems. For both artificial lift systems, the models with the best correlation found thus far are based on a neural network, which resulted in the highest R-squared values when compared to other techniques. This neural network model was validated with the actual information, and the outcomes using this model are presented via a scatter plot in this paper. The plot shows that the prediction for ESP forms a trend around the theoretical best match line. In contrast, the prediction for Beam pump still needs improvement, with the data being scattered around the straight line with a unity slope.

Data science is an emerging technology that recently has provided breakthrough results for big data analysis. This paper will demonstrate the application of such discipline to the area of artificial lift. Machine learning is a promising tool which could help improve human understanding of complex problems, and, in this case, could furnish a durable competitive advantage to the oil and gas industry.
Streamlined Application to Integrate, Standardise, and Automate Well Rate Test Data Analysis
Authors: Al-Mubarak Yousef , Al-Mukhtar Mohammed , Al-Hanabi Mohammed , Mehmood Sajid
Published: October 2019

This paper aims to describe an integrated data analysis and validation application for well testing. This is a computer based application set to work with the different types of wells (water injection, oil producers and gas producers). In addition, it features data capturing, validation, analysis and several techniques for data visualizations.

The conventional well testing process goes through: data capturing, loading, calculations, validation and data archiving. This process was handled by multiple isolated systems that required different workflows based on the data sources. In addition, these systems were designed to handle conventional testing methods such as High Pressure Test Trap (HPTT) separator.

With the introduction of continuous real time measurement technology, such as Multi Phase Flow Meter (MPFM), the volume of the data expands tremendously. This imposes the challenge of big data analytics while ensuring the quality and the consistency of the results. This resulted in a demand for a system to streamline, integrate, standardize and automate the process of well testing. The Integrated Well Rate Analysis System (IWRAS), was developed and deployed to overcome the encountered challenges.

This paper describes well test handling in IWRAS with an example of how the application unified the process workflow for oil producers equipped with MPFM. It will also shows the benefits of utilizing this application in handling real time data.
Remedial Sand Control in Mature Fields: Lessons Learned From Thru-Tubing Ceramic Sand Screen Application in Offshore East Malaysia
Authors: Yeap Wei Jian , Idris Khairul Nizam , Sidek Sulaiman , Cheol Hwan Roh , Kamat Dahlila , Tang Catherine , Zimmermann-Ptacek Johanna , Gundemoni Bhargava Ram , Jackson Steven Richard , Barth Peter
Published: October 2019

Formation sand production is one of the major production challenges in most of the mature fields in Malaysia. Often, failure in primary sand control equipment requires the operators to adopt through-tubing sand screens as remedial sand control. Due to the erosion prone nature of the thru-tubing metallic sand screen, operators are forced to impose limitation on the production rate coupled with stringent surface sand monitoring system to avoid surface flow line leakage and loss of primary pressure containment. Therefore, to seek a more robust technology than conventional metallic screens, alternative technology with through-tubing ceramic sand screen (TTCSS) has been considered with the idea of higher durability and resistance against erosion. This paper will discuss the performance and lessons learnt from the application of through-tubing ceramic sand screen throughout several mature fields in Offshore East Malaysia.

Over the past two years, there have been about twenty-five TTCSS installations in Offshore East Malaysia. Seven pre-mature failure cases were observed, where sands were produced to the surface and even caused leaks on the flow line. The average effective production period for all TTCSS across all the fields ranges from 6 to 11 months. Teardown investigations have been conducted to diagnose the failure root cause.

Most failed TTCSS exhibited similar failure patterns at the end caps, which house the spring compensator. Failure to stop the flow through the end caps led to substantial erosion at spring compensator and base pipe, inducing large flow path for sand production to the surface. Other than the design failure, application failure was observed at the ceramic rings due to their brittleness.

Computational fluid dynamic simulation and laboratory testing have been conducted at the higher incremental production rates to support the observations from teardown inspections, refine the hypothesis of failure mechanism and enable an incremental design change to be modified into TTCSS. In order for TTCSS to be one of the competent candidates for remedial sand control, new improved standard design of TTCSS with strengthened end cap area will be studied to prevent similar failure.
Unlocking Well Potential with CO2 Tracer Application in High Deviation Well
Authors: Kueh Jing Zhi , Lim Jit Sen , Claudius Rick Raynold , Huong Chii Seen , Dev Daevin , Thamilarasu Mohana Ramanee , Abdul Wahab Nurul Syafiqa , Hashim Hazlina
Published: October 2019

In offshore environment, it is common for operators to develop the field with high deviation wells, in order to optimize both field development cost and reservoir drainage. Well intervention for high deviation wells can be difficult, as specialized tools are needed for well intervention in high deviation wells. As such, high deviation wells normally have well issues after 5 years of production.

In Field B, 4 high deviation wells were having unhealthy well lifting, well lifting diagnostics and optimization was needed in order to sustain well and field production. CO2 Tracer Survey was selected for well lifting diagnostics, and all wells were found to have some degree of well lifting issue. With the result from CO2 Tracer Survey, gas lift optimization was conducted, and well was restored to its design condition.
Success Story: Offshore Well Services Using Rigless Offshore Scaffolding Pipes Structure in TBA Field Salawati
Authors: Quraishi Rezi , Mubaraq Munajat , Prayogo Yudie , Yogaswara Andri , Hafeez Al , Robani Aris , Prabowo At Budi
Published: October 2019

Offshore TBA field production has going to the marginal phase where to produce need using artificial lift (gas lift). The gas source for the gas lift is the associate gas produced from the existing wells. The TBA field needs additional gas production to make up the Gas Compressor Unit due to production of the associate gas has declined. This additional gas production will be obtained from top layer of perforation zone. The perforation activity cannot be carried out using rig unit and snubbing units due to limited space deck on tripod platform and high cost operations.

To solve the problem, offshore scaffolding pipes structure (rigless) has become an alternative option to complete the job. This alternative will be supporting as static lifting equipment to R/U all units and running all devices at the platform during well service activities such as perforation, bottom hole pressure survey and gas lift valve replacement.

The success story of using offshore scaffolding pipes structure (rigless) with the steps procedure for installation and dismantle will be discussed in this paper. It is expected that the success of using offshore scaffolding for the operation activity will be a new breakthrough in how to create efficiency in the oil and gas industry.
Asset Value Framing: Maximizing Asset Lifecycle Value Through Opportunity Roadmap Formulation
Authors: Guillory Ryan , Jamaludin Maisarah , Ranjan Rakesh , Abdul Rahim Mas Rizal , Masoudi Rahim
Published: October 2019

As resource owner, host authority, project enabler, and industry shaper, PETRONAS Malaysia Petroleum Management (MPM) has embarked on Asset Value Framing (AVF) since 2016 for its key assets in Malaysia. AVF is designed to provide an avenue for all stakeholders to generate opportunities in an integrated and holistic manner, with values associated, key risks and uncertainties identified, and the enablers and success factors tabled out. It is aimed to evaluate and consolidate all opportunities and synergies both within the Production Sharing Contract (PSC) and outside PSC boundaries with the intent to maximize field life value. The AVF provides a platform to establish a common roadmap shared by MPM and the Contractor to formulate further development steps, maximize economic recovery (MEC), slow production decline, understand the risks, challenge the givens, and to review new technologies to improve field performance.

Short, medium, and long term opportunities associated with reservoir redevelopment and optimization, improved and secondary recovery, near field exploration, well management, operational excellence, cost reduction, facilities optimization, and commercial opportunities are identified and evaluated. An asset roadmap, activity planning, and short term action plans are developed at the end of the AVF workshop, which is agreed and supported by all parties. A clear stack of opportunities for the remainder of the field life, with value and cost associated to each opportunity, become a guiding principle for field growth for all stakeholders. This alignment has enabled consistent planning of project sequencing, resources optimization, and resolution of commercial issues. Opportunities identified in the AVF are later matured, actionized and approved through established MPM channels of Asset Development Integrated Review (ADiR) and Asset Management Integrated Review (AMiR) processes.
Commissioning and Start-Up of Complex Mega Scale Project-Integrated Gas Field and EOR Development
Authors: Ghazali Izrie , Azman M Muaz , Ahmad Shatiry M Sahir , Jaidi M Zamri , Elarafi M Gaberalla
Published: October 2019

In an oil and gas project life cycle, commissioning is notably the moment of truth where the engineered, procured and constructed facilities are verified functioning for the first time. Inability to recognize a project's Commissioning and Start-Up (CSU) unique requirements would increase the risk of project failure. The risk could be mitigated by adopting the right mindset–begin with end in mind. This paper outlines the application of project management processes associated with commissioning discipline.

A multinational operating company undertook a complex mega scale project that aimed to develop an integrated gas field and Enhanced Oil Recovery (EOR) in offshore Sarawak, Malaysia. The project, executed by multiple Package Contractors, is composed of a new central processing platform (CPP), 2 new wellhead platforms, 6 new pipelines, 1 submarine cable, 9 brownfield platforms, 16 new wells and 4 workover wells. Commissioning Team was mobilized as early as Front-End Engineering Design (FEED) and adopted Systemization to decompose the project complexity into manageable constituents. The CSU Philosophy was designed to formulate the Integrated CSU (ICSU) Strategy that systematically drives the construction completion and synergizes the efforts.

Without the strategy, each package would have been focusing in delivering individual objectives that could have compromised the chance of overall project success. However, the timely deployment of it has realigned the execution strategies, noting that offshore project environment is largely dependent on marine vessels arrangement. The strategy managed also to break the silo mentality and encouraged collaboration and communication among the packages and Operations even before the start of the main offshore campaign. The teamwork, of 1200 manpower and 25 marine vessels at peak, was continued offshore and has materialized the introduction of hydrocarbon to CPP 40 days ahead of schedule. Subsequently, the first gas achievement was accelerated by two months ahead of schedule. Additionally, the risk of commercial exposure due to standby of marine vessels and resources caused by clashing of activities, was successfully mitigated.

The experience and lessons learnt from the project can benefit others to undertake similar projects safely and successfully in terms of strategizing, planning and execution.
First Natural Dump-Flood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment with Low-Cost Secondary Recovery
Authors: Abdulhadi Muhammad , Tran Toan Van , Mansor Najmi , Awang Pon Zaim , Chin Hon Voon , Jacobs Stephen , Suggust Alister Albert , Usop Mohammad Zulfiqar , Huong Chii Seen , Zamzuri Dzulfahmi , Abdussalam Khomeini , Khalid Aizuddin , Munandai Hasim , Yusop Zainuddin
Published: October 2019

Natural dump-flood, a low-cost secondary recovery method was successfully implemented for the first time in the Malaysian offshore environment. The dump-flood was initiated by adding perforations in a high-pressure water aquifer and allowing water to cross-flow naturally into a low-pressure depleted reservoir. With investment of 0.4 million USD, the dump-flood has effectively increased the reservoir recovery factor (RF) while increasing the reservoir pressure by more than 300 psi despite being continuously produced.

After 30 years of production, most solution gas drive reservoirs in Field B were idle and depleted. A low-cost natural dump-flood was implemented in reservoir S2, a depleted reservoir, by converting well D-10 into a dump-flood well. The conversion was achieved by perforating a high-pressure water aquifer underneath the S2 reservoir in the same well and allowing water to naturally cross-flow into the depleted reservoir. An existing oil producer, well D-07 was selected as the offtake well that would be produced once the pressure increased. The well operations were both simple and inexpensive as indicated above.

The dump-flood initiative in the first reservoir, S2, was a complete success. A year after the dump-flood was implemented, the offtake well D-07 began to steadily produce 250 bopd compared to its earlier intermittent production. The well production increased to 600 bopd after five years. Pressure survey and production logging results confirmed the positive impact of the dump-flood. The reservoir pressure increased by 300 psi, despite continuous production throughout the dump-flood period. A reservoir simulation model indicated the dump-flood increased the recovery factor of the S2 reservoir by more than 8%. Numerous lessons learned were acquired during the implementation of this first natural dump-flood in Malaysia which serve as a reference for future application. The dump-flood in the S2 reservoir is hailed as a breakthrough, since it helps prove that secondary recovery can be implemented with minimal investment in an offshore environment.

This paper provides valuable insight into the case study of maximizing oil recovery through dump-flooding in an offshore environment. The lessons learned serve as a guideline for this simple and low-cost approach, which is highly recommended for maximizing oil recovery in a mature field, especially in today's low margin business climate.
A Game Changer, Avoiding Production Deferment: First Successful Wireless Ignition System for Floating Flare Unit FFU in Malaysia
Authors: Wei Chuen Kok , Mahmood Shazli
Published: October 2019

The objective of the Floating Flare Unit, henceforth FFU, is to re-route vent gas from a fixed flare platform to a secure unit for performing maintenance that requires the flare platform to be fully shut down. Through this, production deferment can be avoided while maintenance can be carried out concurrently. The requirement of the first of its kind wireless flare ignition system came about with the FFU to effectively and safely ignite the FFU remotely from the safe distance of the platform. This innovation of technology, through the new method tested for wireless ignition of the FFU from the platform had proven to not only provide an effective remote ignition system but also assist in avoiding prolonged production deferment.

A flare ignition system was designed that incorporated a slip stream design which draws a small portion of the flare gas to be burnt away from the main flare gas flow, mixes this with air to obtain the correct stoichiometric mix, ignites this mixture with the high voltage ignitors and uses this smaller flame to ignite the main flare gas as there is no fuel gas supply available for a standard ignition system. The new design incorporated a self-contained skid, which included solar panels, batteries and a radio link mounted onto the FFU as a single unit.

Electrically, the main challenge was to design a system with a very low power consumption to enable the system to last for up to 3 days without solar charging. The new system had a continuous power consumption of 6 W, the power required for the radio receiever to allow remote operation and less than 30 W during ignition. The battery capacity was based on these figures and we easily achieved 3 days of working without re-charging the batteries. The first of its kind was tested in Samarang offshore platform in Sabah which allowed remote ignition of the flare tip of the FFU which was located 200 m. away from the platfrom. With this innovation, a prolonged platform shutdown and loss of production of about 10,000 bopd was avoided. The main benefit of this system is that no power source required for the ignition of the flare system. The flare system also works without any fuel gas supply and finally, the system can be operated from a safe distance of over 300 m. Other challenges included building a unit that is compact enough to proof-store the batteries and other electrical components, ensuring that the high voltage electrodes are with spares and preventing electrical cables from breaking as laid along 200 m. of floating hoses. With the successful deployment of this system, we are looking to replicate this success to other locations in Malaysia to mitigate production loss while performing maintenance of flare system or its platform.
Integrated Production Forecast Evaluation in a Complex Gas Market System - A Multidiscipline Approach to Optimize Gas Supply-Demand in South Sumatra PSC Block, Indonesia
Authors: Ginanjar Mugie , Yusim Sylvia
Published: October 2019

ConocoPhillips Grissik Ltd. (CPGL) is the operator of one of PSC block in onshore South Sumatra, Indonesia. The block consists of 7 gas fields which total gas production and reserves makes it one of the largest fields in Indonesia. As the operator, CPGL generally serves as the seller of gas and services many buyers with differing constraints and demands. Balancing the needs of both buyer and seller is important to ensure a successful long-term supply and demand relationship.

Accurate production forecasting is vital to ensuring optimum field development and management because it is a key input to economic evaluation and subsequent business decisions. To capture the future supply, forecasts are required for both the base production assets and new development projects. Accuracy of the production forecast drives decision making for project approval, project timing, need to engage new commercial contracts and optimization of planned maintenance timing. To ensure that the relationship of supply and demand is captured, the operator use an integrated production forecasting tool called the Gas Planning Tool (GPT).

This paper explains the methodology behind the GPT and how its results are used to support business decisions in the continued development of the PSC block. The methodology accommodates inputs from multiple disciplines: reservoir, commercial, surface facilities, operations downtime, and new drill/facility project schedules. The inputs are integrated and optimized solving for the interaction among input parameters and generates a production forecast that honors all the constraints. The value from the analysis is insights to improve understanding of relationships between different variables and variance between plans.

Gas Planning Tool (GPT) has sucessfully captured the gas supply-demand relationship and helped optimize incremental opportunities, timing of opportunities and idenfied the need for projects and commercial contracts.
Applying Epoxy Resin Technology on Remediation for 3.5 in. Casing Leak: Case Study, South Sulige Gas Field
Authors: Sun Yufei , Fang Anyu , Fan Wenmin , Chen Zhiyong , Liu Sheming , Wang Yang , Li Li , Zhang Xiaoming , Luo Chunlong
Published: October 2019

In the South Sulige gas field, a casing leak was discovered after a velocity string production failure caused well SNXXX-02 to be killed because of water traveling from the formation into the wellbore through the casing leak. This high productivity well urgently needed casing leak remediation to restart production.

Instead of a conventional casing patch approach to repair casing leakage, an innovative solution using an epoxy resin system was applied to recover wellbore integrity and return the well to production. In addition, the resin system does not create casing diameter reduction or restriction during the next velocity installation. However, operational histories and field performance in terms of the capability to mill resin inside 3 1/2-in. casing were rare. This paper discusses a case study of applying the epoxy resin system, a rigless operation using fiber-optic coiled tubing (FOCT) to detect a leak, and then squeezing the epoxy resin using coiled tubing (CT) followed by milling-out after its solidification.

The remediation's effectiveness was determined and examined using qualified wellbore pressure testing; this is the first successful application of an epoxy resin in the South Sulige gas field. The recovery of wellbore integrity helped the operator restart production and maintained the wellbore with no ID restriction for ease of the following velocity string installation.

Most of the wells in the South Sulige gas field are tubingless directional wells with 3 1/2-in. production casing. Implementing a velocity string was widely used as a deliquification method during production.

A casing patch was the primary solution to repair casing leakage in this area. This integrated service of detecting the casing leakage point and applying the epoxy resin presents a new method of well remediation for the operator.
Wider Salinity Range and Lower Water Detection Limit for Multiphase Flowmeters
Authors: Fiore Massimiliano , Xie Cheng-Gang , Jolivet Guillaume
Published: October 2019

With 20 years of operations, multiphase flowmeters (MPFMs) using a combination of venturi and multi-energy gamma-ray absorption have gained acceptance in the oil and gas industry by demonstrating reliable measurement and operational robustness. Nonetheless, some challenging operating scenarios are encountered such as significant water salinity changes in multiphase and wet-gas flows and rapid detection of small water quantities during production.

Although MPFMs are not affected by small water salinity changes, inaccurate flow rates can be calculated when water salinity significantly departs from the initial properties. To maintain measurement metrology as per specifications, the water-point should be manually modified to track variations; however, this operation is time consuming and may incur nonproductive time. Interpreting the multiphase mixture's dielectric constant and electrical conductivity simultaneously measured by a new microwave water salinity sensor at a high data acquisition rate shows that water salinity can be tracked online in the presence of oil, gas, and sand, and small water quantities can be detected rapidly in multiphase and wet-gas flows.

The detection of the first produced water is of paramount importance in many applications, such as for fields with high H2S production, where existing processing plants usually have limitations in treating produced water with dissolved H2S. Early detection of produced water in oil is required, enabling operators to take informed decisions about the oil production strategy as well as water treatment and corrosion protection plans. Extensive analyses in flow loops and field operations with the new microwave water salinity sensor demonstrate that the water detection limit is lowered from the typical ∼1000-ppm water volume fraction (WVF) for the MPFM to a remarkably low 50 ppm.

This paper describes the working principles of a new sensor and method, that enable additional capabilities to maintain accurate water-liquid ratio (WLR) measurement in situations where significant water salinity changes occur and to provide a rapid, much lower WVF detection level. Successful cases demonstrating first-water detection in flow loop tests and in field operations are also presented.