bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Monetisation of an Extremely Thin Oil Rim and Slanted Contact Reservoir, Offshore Malaysia, through Emerging Technologies and Innovative Concepts
Authors: Ahmad Tajuddin Nor Baizurah , Dan Hui Xuan , Tusimin Fuziana , Kawar Saraton , Riza Feisal Sheikh M. , Wahid Ali Nurul Athirah , M. Shah Jamari , Riyanto Latief , Hussain Mansoor , A'Akif Fadzil Nurul Aula , Sakdilah M. Zaki
Published: October 2019

The scope of the paper is to share a case study of a successful horizontal well completed within an extremely thin oil rim of ~10ft with bottom water. This paper highlights the differentiating activities undertaken to deliver the well despite the challenges of extremely thin oil rim, strong water drive and uneven current fluid contacts.

Prior to drilling this well, attempt was made to mitigate the uncertainty regarding the current gas-oil contact (GOC) and oil-water contact (OWC) by carrying out cased-hole logging in some of the adjacent wells, and re-sequencing and re-optimizing the location of two of the wells targeting the reservoirs below. This obviated the need for the pilot hole and thereby resulted in a cost saving of ~USD 1Million. Furthermore, the dynamic simulation model was updated to create a fit-for-purpose model with the latest OWC and GOC, so as to be able to test various trajectories.

While drilling, the well was drilled with real-time reservoir mapping-while-drilling technology and integrated with real-time reservoir characterization, fluid typing and trajectory modification, while maintaining Dog Leg Severity (DLS) below 3 deg/100ft for the ease of completion run.

Completion was then optimized with viscosity-based inflow control orifices. Post drilling, dynamic and well models were calibrated to the actual results to determine optimum production rate for the well life.

The horizontal well was successfully navigated and optimally placed in the extremely thin oil column. Tilted contacts were encountered in the targeted subunits where actual current contacts came in ~20ft shallower at heel and ~10ft deeper at toe compared to prognosis. Consequently, the heel landed at a 5ft stand-off from water, and the toe landed 18ft stand-off from water and 6ft stand-off from gas.

The well was successfully unloaded and tested at a controlled oil rate of 2887 bopd, 50% higher than planned target.

This paper presents the entire process from well planning until well production tie-in. This was achieved through the integration of subsurface understanding with the utilization of the appropriate technology. Finally, the management's trust in the capability of the team members ensured deliverability of the target production rate and the consequent booked reserves.
DrillersAssist; An Integrated System for Real-Time Drilling Process Automation
Authors: Mirhaj Ahmad , Sandrib Bjarne , Lien Morten
Published: October 2019

Drilling automation is a rapidly developing area of technology that is seeing growing interest within the drilling industry. MHWirth as one of the world-leading providers of complete drilling rig packages including the equipment software systems has been focusing on developing a set of different smart modules in order to perform more efficient operations.

This paper describes the MHWirth's DrillersAssist. It is a Smart Module that assists the driller with downhole operations. It offers automation of well construction sequences, and protective limits safeguarding the well. This helps with efficient and consistent well construction.

All functions and protective limits in DrillersAssist are configured by the operator based on input from the well plan, mud logger and other sources.

It contains three drilling sequences; mud pump start-up, hole cleaning and friction test sequences.

DrillersAssist also provides several well protection functions. It is worthy to mention that the operator can easily override the protection if required due to operational reasons.

Thereafter the results of implementing DrillersAssisst on Transocean-Enabler rig for drilling operation of a well in Barent-sea will be presented. The results show its first pilot run had quite some cost reduction compared to when drilling operation performed without the use of DrillersAssist.
Unify Exploitation and Exploration Prospect to Revive Idle Marginal Offshore Brown Field in South East Sumatera, Indonesia
Authors: Waskito Lucky Bagus , Gunawan Heri , Nugroho Pranowo , Senoaji Wahyu
Published: October 2019

Located offshore South East Sumatera Indonesia, C-SY field is a structural trap with 4-ways dip closure and multiple reservoir targets with excellent rock properties, considered a marginal field and currently idle for 8 years. Challenges faced in reactivating C-SY field are high investments compare to other well service proposal and have limited reserves. The objective of this paper is to revive idle marginal offshore brownfield C-SY by increasing value of reserves and economics value. In order to do so, all prospects within C-SY area need to be assesed, including exploration prospects with high geological chance factor.

The evaluation process worked simultaneously by exploitation and exploration team. The exploitation team worked on re-estimate OOIP and reserves of existing reservoir by structural interpretation, reservoir characterization analysis using attributes, Decline Curve Analysis & Material Balance Analysis. While the exploration team worked on finding other reservoir prospects by doing prospect identification from 3D seismic analysis, structural play analysis, closure identification and migration pathway from kitchen to prospect area, calculate OOIP. Result from both teams were combined to estimate reservoir behavior and production forecast. The next step of evaluation was to create multiple cases of possibilities and calculate the economics to find the best and possible case with minimum calculated risk.

Collaboration between Exploitation and Exploration has lifted the value of C-SY idle marginal brown field, new structure has been found with promising reserves and initial production. Initial production C-SY field after the collaboration is 1,200 BOPD from previously 150 BOPD, while remaining reserves increase 3 times higher up to block expiration contract in 2038.

Developing marginal offshore mature asset is a risky business, especially considering high volatility in oil prices. Collaboration and technology are vital to escalate the economic value and achieve higher recovery factors. Application of the multidisciplinary methods was considered as an appropriate way to approach and manage a complex marginal mature field redevelopment.
Innovative Approach to Production Optimisation Using Customised Integrated Surveillance Approach
Authors: Kumar Pankaj , Affeld Christian , Zdenkovic Nick
Published: October 2019

This paper presents the innovative way of Production Optimisation using fit for purpose customized Integrated Surveillance approach which helped to manage a complex field in West Africa in a very effective manner in the low-cost environment. Integrated surveillance approach, workflow overview and the best practices are provided to demonstrate effective field management.

An integrated surveillance approach was based on the fundamentals of addressing day to day challenges in a seamless and efficient manner. To enable this, a customized IST (Integrated Surveillance Tool) and standard workflow was developed to meet the requirements. The IST was tailored specifically towards making the most relevant data available to the evaluation team. IST acted as a single source to fetch all the critical data relevant to wells and key process components.

All critical data were then integrated and reproduced in a way to enable time effective decision making. For a selected well, relevant information was just a mouse-click away; this include the well completion, geological cross-sections, production test data, lift gas response curve, facility operating envelope, actions log, wells follow up document etc. Thus, detailed analysis could easily be carried out in one application. The IST allows extracting and updating wells and facility operating envelopes, performing exception-based surveillance, performing wells ranking either on a cluster or full field basis, performing lift gas optimum allocations on a subset or field level basis. In the regular optimization forums, IST was used to analyze wells per cluster, facility performance and integrated system to generate opportunities and quick actions to generate easy production gains. Workflow and processes are streamlined for effective time management.

The integrated surveillance approach enabled improvement in production gains in the order of about 20% through identification of issues, solutions and opportunities in a fast and efficient manner; such as bean-up, choke changes, gas lift optimization, creaming high GOR or high WC wells, zone changes etc. in an effective way.

An integrated and systematic approach to Well, Reservoir and Facility Management still represents a challenge in the industry; however, development and usage of customized integrated surveillance approach showed that the processes can be simplified and made more efficient to maximize production.
Application of Exploratory Data Analytics EDA in Coal Seam Gas Wells with Progressive Cavity Pumps PCPs
Authors: Saghir Fahd , Gonzalez Perdomo M. E. , Behrenbruch Peter
Published: October 2019

Artificial lift methods typically drive Coal Seam Gas (CSG) wells, and Progressive Cavity Pump (PCP) is the preferred method of lift with Australian CSG operators. CSG wells in Australia are typically equipped with necessary instrumentation and automation systems to provide real-time data gathering for monitoring and control purposes. Real-time data gathered from CSG wells presents an opportunity to better understand PCP performance by identifying anomalous pump behavior.

However, before undertaking any real-time analytics exercise, it is pertinent to carry out Exploratory Data Analytics (EDA) to understand time series data behavior and extract relevant features; and this exercise is particularly important with multi-variate data sets. Obtaining significant data features from multivariate time series data can help define which analytics and machine learning methods could be exploited to analyze PCP performance in near real time.

This paper will discuss EDA methodologies that can help streamline time-series data normalization and feature extraction techniques. A three (3) year time-series dataset, gathered from forty-two (42) CSG wells, will be used to showcase EDA methodologies utilized as part of this research. All EDA activities covered in this paper are based on the Python programming language and its supporting libraries.
The Application of Drill Cuttings to Evaluate the Fracability in Unconventional Shale Gas Resources
Authors: Shi Xian , Jiang Shu , Wang Zhixuan , Xiao Dianshi , Sun Xiaofei
Published: October 2019

Selecting a good fracturing candidate that can maximize the complex fracture network in advance is beneficial for enhancing the fracturing effectiveness and the economic development of shale gas reservoirs. Brittleness is generally used to evaluate the capability of complex fracture networks by using critical mechanical parameters, but these parameters must be acquired from well logs and time-consuming triaxial core-scale mechanical tests. However, considering the physical and chemical instability of shales, standard-sized core plugs are difficult to obtain in some zones of interest. Thus, the analysis of drill cuttings by the combination of SEM/EDS (scanning electron microscopy-energy dispersive spectrometer) analyses and grid nanoindentation was used to replace conventional standard measurements on high-quality sized cores. A significant advantage of this technique is that drill cuttings can be collected from most wells. Furthermore, in contrast to traditional tests, the petrophysical and mechanical properties of shales can be characterized simultaneously. Thus, a comprehensive brittleness model can be established based on the mineral brittleness and mechanical brittleness. Experimental results demonstrate that the integration of grid nanoindentation and the deconvolution technique can provide reliable estimations of the homogenized Young's modulus and Poisson's ratio, while EDS mapping can provide accurate mineral compositions of the indentation area. The method is successfully applied to evaluate the brittleness of a shale gas well in a shale gas field in China, which demonstrates that this method is a fast and cost-efficient way to evaluate the brittleness of shale gas formations with a small volume of rock samples.
Establishing Proper Abandonment and Site Restoration Strategy to Reduce Uncertainty in Developing Mature Offshore Field: A Case Study of ONWJ Field in Indonesia
Authors: Sajjad Farasdaq Muchibus , Hadi Prasetyo Abraham , Chandra Steven , Wijaya Budi Rivai , Naja Savinatun
Published: October 2019

Abandonment and site restoration (ASR) is one of the responsibilities of Oil and Gas Company for the country where it operates. The ASR covers plug and abandon (P&A) of wells and dismantling of surface equipment in order to restore the environment as close as possible to its original state.

Current practices in Indonesia's oil and gas business does not put P&A as one of the top priorities, compared to other engineering aspects in petroleum engineering. Therefore, P&A is sometimes regarded as a formality.

A case study where long term oil and gas exploration and production with unique rock mechanics in Offshore North West Java (ONWJ) Area has caused subsidence and inherently leading to both production operation and well integrity issues. Several issues namely casing deformation and detachment from main casing strings have been observed and is likely to put harm to oil and gas production in ONWJ Area. Casing issues such as buckling and crumpling, as well as the presence of micro cracks will present complications in safely plugging and abandoning the affected wells.

Recommendations based on current practices around the world as well as mitigation solutions done in ONWJ Area such as mechanical stress and/or strain release combined with well condition evaluation and monitoring is maximized as an input to properly design safe and cost efficient P&A strategy for complex, marginal, and offshore wells with integrity issues. This research is aimed to become a benchmark for future uses of P&A not only in ONWJ area but also in Indonesia.
Achieving Exceptional Efficiency of Gas Lift Design in Offshore North West Java Field Using Dynamic, Time-Based Equalised Method
Authors: Muchibbus Sajjad Farasdaq , Wirawan Alvin , Naja Savinatun , Suganda Wingky , Pramana Harris , Indro Axel Perwira , Chandra Steven
Published: October 2019

Offshore North West Java is a mature oil and gas field located in northern part of Java Island. Most of the wells are producing with gas lift system from the abundant source of gas in the field. Through forty years production life of this field, the conventional gas lift spacing design is found out to be not optimum. Many unloaders at the upper part of the completion aren't necessary during its production stage and usually will be changed into a dummy valve during gas lift valve redesign (GLVR) operation. These excessive number of valves may cause many problems, such as limited gas that can be delivered through the orifice, higher probability of valve and installation failure, and many more. These conditions will lead to un-optimum production rate.

A new innovative method of gas lift spacing design is proposed to solve the problem by optimizing the number of gas lift valves installed in the completion. In conventional gas lift spacing design, completion fluid level is often represented static at the surface using a static fluid model. In fact, completion fluid level tends to change over time due to fluid infiltration into the reservoir. By emphasizing this fluid infiltration into the reservoir, equalized method is created. This equalized method alters the spacing design starting depth from the surface into the depth which equalized condition between bottom hole and reservoir pressure is reached. By combining Darcy' law and hydrostatic pressure formula, a new equation is derived. It is able to forecast the time needed to reach the equalized depth and also the depth itself.

To verify the newly developed method, a case study of Well-X is presented. To enhance Well-X production, a gas lift system is required. Using a predetermined compressor pressure, the conventional gas lift spacing method yields a total of eight unloader valves. In contrast, the equalized method reduced the number of unloader valves required to a total of four. The example has proved that the equalized method is not only able to reduce the chance of failure in the installation, but it also results in a higher gas lift operating pressure, higher gas injection capacity, and in the end, 5.6% of higher oil production rates obtained compared to the conventional method.

The novelty of this paper is an optimized gas lift spacing design by using the equalized method. For further implementation, this method can be applied in most oil well cases with gas lift system, for a better economic profit.
Successful Deployment of Horizontal Openhole Gravel Pack with Alternate Path Technique and Filter-Cake Breaker Placement for Effective Well Cleanup Offshore Myanmar
Authors: Ogueri Chidi , Somkleeb Paneepan , Falla Michel
Published: October 2019

The Badamyar project is an offshore gas field located 220 km south of Yangon in the Republic of the Union of Myanmar. In February 2017, four gas wells were successfully drilled and completed using horizontal openhole gravel packing in the Badamyar gas field. The downhole completion design adopted was an alternate path technique using filter-cake breaker deployment for effective well cleanup.

Initial geomechanical studies performed in the field show that the sands have low mechanical strength; consequently, they are unconsolidated. This was verified with sonic measurement of 120 us/ft (more than 110 us/ft). An active sand control technique was deemed necessary to ensure a robust well completion with longevity for expected gas production. Based on the comparative risk analysis conducted by the operator for various types of sand control and reservoir drainage, a horizontal openhole gravel pack method was selected to complete the four wells.

During the well planning stage, the following specific challenges were identified for the installation of the lower completion: Openhole gravel placement method; alpha/beta wave vs. alternate path technique considering low fracture gradient to achieve 100% pack efficiencyEfficient gravel pack carrier fluid for the selected methodExpected long drain hole in a clay sensitive environmentEffective filter-cake cleanup post-gravel packVery fine, poorly consolidated, and immature shaly sands

Downhole sand control equipment deployment, gravel pack placement, filter-cake removal, and initial production results have proven the selected gravel pack method to be successful in the Badamyar field. This paper presents the measures taken to address the project challenges during the design and execution phase and the results achieved.

The success achieved can be adopted for the completion of high-rate gas wells with similar reservoir conditions in this area and beyond.
Reducing Breakdown Pressure of Tight Reservoirs Via in-Situ Pulses: Impact of Mineralogy
Authors: Al-Nakhli Ayman , Zeeshan Tariq , Mahmoud Mohamed , Abdulraheem Abdulaziz
Published: October 2019

Industrial growth increases the demand for natural gas worldwide, which is considered as one of the cleanest types of fossil fuels and most reliable energy source (BP, 2013). Unconventional gas represent a giant resource of natural gas, however, requires massive fracturing. One of the challenging problem that operators face is the high breakdown pressure for deep and tight reservoirs. Several lost potentials are recorded worldwide due to high breakdown pressure that exceeds pumping limitations or completion rating.

Several attempts were tried to reduce the breakdown pressure by cyclic fracturing, low viscosity fracturing fluid, perforations and high pressurization rate. However, even with the existing techniques, still high breakdown pressure present a persistent challenge.

Increasing the injection rate of the fluid into the rock corresponded to a lowering of the breakdown pressure. The higher injection rate allows more fluid to enter the shale porosity thus transmitting the injection pressure to more points within the shale formation, which reduces the breakdown pressure. The developed methodology reduces breakdown pressure and enables fracking high stress rocks by increasing the injectivity prior to fracturing. Thermochemical will be injected to create microfractures, improve permeability, and reduce young's modulus of tight reservoirs prior to fracking. By creating microfractures and improving injectivity, the required breakdown pressure will be reduced, and fracturing will be enabled. Moreover, experimental results showed that thermochemical treatment reduces young's modulus of the rock, thus reducing rock stiffness.
A New Method for Predicting CO2 Minimum Miscibility Pressure MMP Based on Deep Learning
Authors: Dong Peng , Liao Xinwei , Wu Jiaqi , Zou Jiandong , Li Rongtao , Chu Hongyang
Published: October 2019

The CO2 enhanced oil recovery (EOR) method is widely used in actual oilfields. It is extremely important to accurately predict the CO2 MMP for CO2-EOR. At present, many studies about MMP prediction are based on empirical, experimental, or numerical simulation methods, but these methods are inefficient in calculation, with low result accuracy and high computation burden. Therefore, more work needs to be done. In this work, a fully connected neural network (FCNN) is developed to facilitate predict the CO2 MMP, based on multiple mixing cell methods (MMCM) and slim-tube experiment. With the results of the slim-tube experiment and the data expansion of the MMCM method, a FCNN model that predicts CO2 MMP by the full composition of the crude oil and temperature is trained. To stabilize the neural network training process, L2 regularization and Dropout are used to address the issue of over-fitting in neural networks. Training results show that FCNN with Dropout possesses higher prediction accuracy. Then, based on the validation sample evaluation, the mean absolute percentage error (MAPE) of the FCNN model is 6.99. Finally, the improved FCNN model is evaluated by six samples obtained from slim-tube experiment results. The FCNN model proposed in this paper has extremely low time cost and high accuracy to predict CO2 MMP, which is of great significance for CO2-EOR.
Where's the Water Coming From? A Combined Formation Saturation, Production Logging, Water Flow, and Leak Detection Diagnosis Deployed on Coiled Tubing
Authors: Imrie Andrew , Bagir Muhammad , Himawan Glen Ricky , Iyer Mahadevan S , Ariewijaya Aditya
Published: October 2019

An offshore gas-producing well recently encountered an increase in water production. The well featured multiple completion zones, creating ambiguity and uncertainty in the water source and production zone. Due to the significant deviation of the well, coiled tubing (CT) provided the means of conveyance for an advanced array of well diagnostic tools selected to evaluate the multiple downhole scenarios that may lead to the increase in water production, including completion failures, saturation depletion, and flow from unexpected sources.

This paper discusses the integrated analysis and methodology behind the successful determination of the water source in an offshore gas-producing well. The deployed tools include a multi-detector pulsed-neutron tool (MDPNT), an advanced acoustic array leak detection tool (ALDT), and a suite of production logging tools. The logging suite was tailored to address the wealth of possible scenarios for the increase in water production. Logging was performed in shut-in and flowing environments to understand the behavior of the well in dynamic conditions. Following the acquisition, the data sets were integrated and analyzed, leading to the successful determination of the problem zone.

The well featured two perforated reservoirs, each separated by packers and sliding sleeves. The deeper zone was determined to be water-saturated and should have been isolated by a closed sliding sleeve beneath a packer. MDPNT oxygen activation eliminated the possibility of channeling between the water-producing zone and the gas-producing zone. The packers in the well proved to be intact based on the interpretation of the ALDT acoustic noise data and the count rate reading of the MDPNT. The investigation then focused on the completion string jewelry and involved computing a two-dimensional (2D) radial flow map from beamforming of the ALDT-recorded acoustic noise activity around the wellbore, which revealed a closed sliding sleeve within the water-producing zone was likely leaking and, therefore, ineffective. The saturation results using the MDPNT in sigma mode indicated that the perforated reservoirs contained a low remaining gas saturation. Following the diagnosis, the operator ensured the sliding sleeve was closed reducing water production by more than 50%, resulting in an improved well performance.

Compatibility with CT enabled the advanced suite of pulsed neutron, acoustic noise array, and PL wireline sensors to be deployed in a well with significant deviation. As the water production source was unknown, many possible scenarios had to be tested. Careful job planning and interpretation of the acquired log data eliminated scenarios and led to the conclusion that the completion integrity was compromised at a sliding sleeve, therefore enabling flow from a water-saturated zone.
Factors Affecting Cement Quality of Intermediate Casing in the South Pars Gas Field: A 24-Well Case Study
Authors: Bahrami Esmaeil , Zangenehvar Alireza , Mohseni Arman , Mortazavizadeh Seyedmorteza , Safari Alireza , Aryanfar Yasha
Published: October 2019

Cement behind casing, as the critical component of well integrity is a real challenge all over the world. Despite the efforts drilling operators and service providers dedicate to this phase of well construction in the South Pars gas field, final set cement quality does not establish zonal isolation in 9 5/8" casing and 12 1/4" openhole section.

In order to study this issue, twenty-four wells have been analyzed based on theoretical analysis, close hands-on operations and track record of cementing in the field. Data were acquired from the daily drilling reports, data acquisition system of cement units, mud logging records, daily mud reports, cement slurry laboratory test sheets and wireline log records.

The main effective factors on cement quality have been studied in four groups namely: well preparation, slurry design, mud removal and post-cementing practices. Good and poor quality cement in all wells have been compared with actual field parameters using a cementing displacement simulator software. Structural stress model has also performed for one of the wells whose cement was prone to be impacted by post cementing practices.

Results have been obtained over one year of parallel laboratory testing, field experience, simulation and evaluation. The simulations results illustrate turbulent flow is not practical for cementing of this section and effective laminar flow technique shows an efficient alternative, however all criteria of this technique could not have been fully met due to some well restriction. The results reveal mud removal parameters in terms of casing centralization have significant effects on the final cement quality in this field. Cement quality devastation persisted even in cases where the cement slurry properties were modified and used in four wells in order to evaluate slurry design impact degree on final set cement quality. The stress model results illustrate that imposed stress on the well exceeds the compressive and tensile strength of the cement sheath. These results reinforce the idea that mud removal and post cementing practices govern the cement quality in the field.

This paper is a comprehensive study of all effective parameters on cement quality in 9 5/8" casing cementing and highlight the main sources of cement quality devastation in the field and it can be used as a guideline for cementing similar cases around the world.
A Robust Method to Quantify Interwell Connectivity of Offshore Heavy Oil Field Using Performance Data
Authors: Liu Yingxian , Ma Kuiqian , Cai Hui , Chen Cunliang , Wang Xiang , Dong Peng
Published: October 2019

Interwell connectivity is an important parameter for reservoir characterization and is essential for making decisions on optimization of water injection and infill wells. Unlike ordinary reservoir, starting pressure gradient is an important characteristic for heavy oil reservoir. For better quantifying the interwell connectivity of heavy oil reservoir, a robust method to quantify interwell connectivity using performance data is proposed.

Considering the characteristics of the starting pressure of heavy oil flow, the production model between the yield and the pressure difference is established. And the production model is linear when the steady flow and the water content are relatively stable. And then, a time constant function is constructed to characterize the lag and attenuation of waterflood signals in formation propagation. By substituting the production model and the time constant function into the equation of material balance, the relationship model between cumulative liquid production and the cumulative water injection (CPIM) is obtained through two integrals. The cumulative relation overcomes the instability of instantaneous relations. The solution of the CPIM is transformed into an optimization problem by using the least squares principle. And the quantitative connectivity evaluation is obtained by using PSO algorithm.

Compared with the single-well dynamic analysis, the accuracy of the CPIM is over 90%, but the spent time is less than half of the single-well dynamic analysis. In addition, the paper presents a case study to compare findings from the results of the CPIM and the use of interwell tracer. The results obtained from the CPIM shows good agreement with the results obtained from interwell tracer. And the CPIM can be applied to some wells which can not be carried out tracer test because geological conditions of these wells are particularly complex. In summary, this CPIM is not only feasible, but also saves a lot of time and money.

The CPIM can be used to quickly estimate reservoir properties and infer interwell communication in primary and secondary recovery from available data with high confidence. The method was applied to Bohai oil field which is effective for establishing well interaction pattern. Recommendations were given to improve waterflood efficiency.
Study on Risk Prediction of Hydrate Formation in Deepwater Gas Wells During Production Process
Authors: Liu Wenyuan , Hu Jinqiu , Sun Fengrui , Sun Zheng , Chu Hongyang , Li Xiangfang
Published: October 2019

Recently, more and more attention has been paid to the development of deep-water gas wells around the world. However, hydrate formation in string has always affected the safety of deepwater gas well production and there is no accurate risk prediction method currently.

In this study, a more optimized and practical prediction model for hydrate formation region (HFR) was established. The model has been applied to deepwater gas wells and the influence of typical factors on HFR is analyzed. The conclusions are as follows: (a) the gas temperature decreases gradually from bottom hole to wellhead, and the rate of decline is obviously faster near mud line. (b) under low gas recovery rate, the effect of heat transfer on gas temperature reduction is more obvious, but at high gas recovery rate, the opposite is true. (c) because of the pressure change in wellbore, the hydrate equilibrium temperature gradually decreases with the decrease of well depth and HFR often appears in the upper half of wellbore. (d) the increase of gas production and formation temperature is helpful to shorten the length of HFR in the string, which is due to the increase of gas production and reservoir temperature increases the temperature distribution in the pipe string. (e) the hydrate equilibrium temperature and HFR decrease by increasing inhibitor content. Increasing the use of hydrate inhibitors is the most practical and effective measure to reduce hydrate risk.

In the production process of deepwater gas wells, the effective location of HFR is very important to the production safety of deepwater gas wells. This research can be helpful to the research of wellbore flow assurance during the production of deep-water gas wells.
Study on the Adjustment Control Technology of Multi - Layer Fire Flooding in a Common Heavy Oil Reservoir
Authors: Feng Tian
Published: October 2019

In this work, we adopted the adjustment and control technology of fire flooding in block S which is a common heavy oil multi-layer reservoir. We aim to tackle the problems of large inter-layer utilization differences and uneven advance of plane fire line after areal fire flooding in block S which has been implemented for about 12 years.

Block S contains roughly 30 oil layers longitudinally, with an average single layer thickness of 2.2 meters. The interlayers are well developed with a thickness of about 4 meters, which is in line with the basic conditions of layered fire flooding development. Based on the characteristics of geological body development, we comprehensively analyzed the development bottleneck problems and potential conditions of subsequent development in this area by means of the identification method of combustion state, analysis of field monitoring data, numerical simulation research and dynamic production rule research.

Based on the principle of increasing the using degree of fire flooding and improving the combustion effect, we put forward the adjustment and control technology of fire flooding suitable for this kind of reservoir. First of all, based on the characteristics of reservoir development, we reasonably combined the displacement interval to effectively strengthen the longitudinal use of the fire line. Secondly, through the reasonable configuration of areal pattern and linear pattern, the spread range of the plane fire line can be expanded. At last, the optimum combustion condition of fire drive is created by reasonably optimizing ignition temperature and gas injection intensity. Field practice has preliminarily demonstrated that the combustion state of typical well groups can be improved by such adjustment and control techniques. We believe that the recovery rate can reach 55% by gradually implementing regulatory measures.

In summary, we demonstrate the adjustment and control techniques for multi-layer fire flooding in medium and deep common heavy oil reservoirs. As a replacement technology for conventional areal pattern fire flooding, it can further improve the development effect and improve recovery.
A Unique Completion Design Using Perforated Drill Pipe in the Onshore Southern Sumatra Basin
Authors: Tejo B. , Singamshetty K. , Tupamahu L. , Gunawan I. , Nugroho W. , Satriya Y.
Published: October 2019

An operator recently drilled and completed an onshore well in South Sumatra by intentionally leaving 3-1/2 in. drill pipe in the hole, to be used as the lower completion string. This paper documents the design and execution of this unique drill pipe completion idea, overcoming challenges during drilling due to unanticipated formation collapse, leading to multiple sidetracks. The reservoir contains dry gas with >30% CO2 inside naturally fractured basement rock. Wells in this area are usually drilled with total losses throughout the reservoir section and completed by running a perforated liner.

In the 3rd and final sidetrack, the drill pipe completion idea was successfully executed resulting in a well that is producing ∼40 MMSCFD. The idea was selected after technically evaluating other viable options such as liner drilling using 5-1/2 in. casing or drilling with continuous water injection and then running the liner. The drill pipe completion option provided the highest chance of success to reach total depth (TD) in a single bit run while serving as a mechanical conduit in the wellbore for production and providing a barrier against hole collapse. The detailed planning conducted to finalize the drilling bottom hole assembly (BHA), perforating gun performance, drill pipe cutter, production rate impact, erosional and corrosion impact of using drill pipe as completion will be explained in the paper.

Operationally, after the well was drilled to TD, 1-11/16 in. strip guns were used to perforate the 3-1/2 in. drill pipe and then the pipe was severed using a non-explosive plasma jet cutter and left in hole. A fishing overshot was then run on the bottom of lower completion liner to swallow the cut drill pipe and provide future intervention capability. The upper completion was subsequently run and set prior to rig demobilization.

This unique application of a sacrificial drill pipe completion, also termed as the "crazy drill pipe idea" by the operator, generated a lot of discussion and interest within the oil and gas industry in Indonesia. We are hopeful that the technique and application discussed in this paper will provide valuable insight into this alternative completion design for use in depleted and unstable formations, where opportunities to pursue other viable options are limited.
Escalating Value of Idle Marginal Offshore Brown Field through Collaboration and Technology in South East Sumatera, Indonesia
Authors: Waskito Lucky Bagus , Gunawan Heri , Nugroho Pranowo , Luthfan Mochammad
Published: October 2019

A collaborative effort between subsurface, operation and commercial team has successfully escalated the value of idle marginal offshore brown field in south east Sumatera, Indonesia. Over the past several years Lidya field was idle due to wellbore and facility problem, big investment value are needed to reactivate Lidya field and it creates hesitation in management decision, also there is a security issue to be considered. This paper describes the methodology applied in evaluating all aspects considered to mitigate the investment risk, escalating economical value and to ensure all parameters perform as expected.

The evaluation method divided into three major parts, the first part starts from subsurface study that involving geophysical processing, geologist re-interpretation, and reservoir engineering analysis, one of the most important factors to be taken into account is the necessity of a good understanding of the reservoir in order to increase the possibility of success. The second part is operation evaluation, it captures production engineering analysis from well integrity assessment to artificial lift selection, facilities observation from pipeline assessment to platform refurbishment option and also designing new security system to prevent cable thievery. The third part is the most crucial part to justify the value of Lidya marginal field reactivation project, challenges in this part also interesting, because production sharing contract term has changed from Cost Recovery to Gross Split mechanism, several cases was observed by commercial team to find the very best case with the least risk that might occur and affect the investment.

As a result, the value of Lidya idle marginal field was escalated. It can be quantifed from oil rate that increase from 150 BOPD for the last five years before it went idle to 700 BOPD for full cycle project. Economic side also appealing, observation multiple cases led to optimum case that can give total contractor net cash flow at almost 19Million USD in new fiscal term Gross Split mechanism, this number is 4 times higher than Cost Recovery mechanism for contractor profitability.

Developing marginal offshore mature asset is a risky business, especially considering high volatility in oil prices. Collaboration and technology are vital to escalating the value and achieving higher recovery factors. Application of the multidisciplinary methods was considered as an appropriate way to approach and manage a complex marginal mature field redevelopment.
Analysis Method of Cement Sheath Damage Zone After Perforation
Authors: Yan Yan , Guan Zhichuan , Yan Weijun , Wang Hongtu
Published: October 2019

The combined technology of perforation and hydraulic fracturing has been the main development method for unconventional oil and gas to date. However, perforation can cause crack damage to cement sheath or de-bonding of the cement interfaces, resulting in fluid channeling during hydraulic fracturing. From an operational perspective, it is thus critical to be able to characterize the degree and range of cement sheath damage after perforation. To achieve the objective, a numerical method of perforation is set up based on the ALE (Arbitrary Lagrange-Euler) algorithm in LS-DYNA software. The numerical results are verified by the ring target simulation test. The cement-interface damage zone shapes like a saddle after perforation, and there is a narrow range of damage around the perforation tunnel. The damage zone is minimized with the enhancement of cement compressive strength but conversely with shear modulus. Cements with lower shear modulus and higher compressive strength should be selected during well cementing for reducing cement sheath perforation damage. Additionally, a shaped charge with smaller liner diameter is more effective in enhancing the seal integrity during hydraulic fracturing.
Multiscale Digital Rock Modelling for Reservoir Simulation
Authors: Reshetova Galina , Cheverda Vladimir , Lisitsa Vadim , Khachkova Tatyana
Published: October 2019

We present analysis of sandstone micro-CT scans obtained with different resolution. We show that use of fine resolution (about 1 micrometer per voxel) do not provide valuable information about the core structure and for the pore surface analysis and makes the sample nonrepresentative even for porosity estimation. Scans with resolution of 3–5 μm per voxel allow to get statistically reliable estimates of the reciprocal pore-to-core distribution, topological properties of the pore space and transport properties of the sample. Using this information one can reconstruct the macroscopic model of poroelastic media.
Simplify Bypass Pig Speed Calculation Using Probabilistic Method
Authors: Abdul Samad Khairul Anwar , M Nadzeri M Shahrustami , Liew Patricia Fung , Lau Kheng Hoong , Mat Isa Badlishah , Abdul Rasyid Ramlah , M Shahrin M Hafizuddin
Published: October 2019

One of the challenges in pipeline operational pigging in multiphase pipeline is high Pig Generated Volume (PGV) liquid slug that arrives at the end of the pipeline receiving system. This causes process upset at the receiving plant, which in turn causes production deferment each time pigging activity is performed. Introduction of bypass pig for cleaning activity is one of the best solutions to manage the arriving liquid slug at the receiving end to allow ample time for the plant to control the arriving slug and evacuate liquid without initiating a process upset. Usually to design the bypass pig would require specific hydraulic pipeline simulation with expertise and experience personnel to perform the assessment. Meanwhile, pipeline operator are also dealing with a fluctuating gas flowrate, temperature and pressure during pigging operation which effect the selection of bypass pig design. There are records of bypass pig stalled which happened as a result of not considering the variation of these input variables. This paper elaborates alternative calculation methodology using Monte Carlo probabilistic method to assess input variables via a spreadsheet, prior to determining the final bypass pig design.

Groot (2015) provide a detailed explanation on bypass pig calculation using mass balanced approach to determine the bypass pig speed based on specified bypass opening. To determine the bypass pig speed, the gas velocity through bypass opening is subtracted from gas mixture velocity. For this case study, bypass pig with disc type is used. The minimum and maximum value for input parameter is used in the calculation using RANDOM functions in the spreadsheet. The calculation is repeated for 10,000 iterations to get the different result based on random range of operating parameter that has been set earlier. The calculation boundary is determined whereby for this case is the bypass pig speed. Result which fall within the boundary will determine the success rate of the bypass pig design, without pig stall or over speed.

Using Monte Carlo probabilistic method, the optimum bypass pig opening could be determined to avoid over speed or pig stall. Probabilistic method enables the user to analyze using descriptive statistic ie. minimum, maximum or average pig speed from various conditions. In conclusion, probabilistic method has significantly help the user to assess the bypass pig speed with fluctuation of operating parameters using simple spreadsheet.
Asset Wide Optimisation: How a Real-Time Integrated Production System Model for Optimisation Keeps the Lights on in Brunei
Authors: Abdullah Zulfikri , Briers Jan , Jamil Mariana , Sahu Sambit , Tan Jun Xian , Zainal-Abidin Hadini
Published: October 2019

Brunei Shell Petroleum (BSP) has a complex production gathering network that comprises of multiple onshore and offshore Assets. Gas and oil is produced under different pressure regimes, and with varying compositions. The production from each asset can be routed in multiple ways to different customers, each with their own compositional requirements. Crude oil and gas is routed to Brunei Liquified Natural Gas (BLNG) and Seria Crude Oil terminal (SCOT) for further processing before export to external customers. Apart from export, other customers include BMC (Brunei Methanol Company), Brunei Shell Refinery (BSR) and Department of Electrical Services (DES), fueling Brunei's vehicles, homes and local industries.

Currently this complex production network is managed by a dedicated Operations Control Centre (OCC). The central OCC team coordinates, monitors and controls the hydrocarbon activities to meet customers' quality and quantities demand by engaging with the 4 individual Asset Operation teams, as well as customers, to optimize production at the Pan-BSP system level.

With the introduction of the Integrated Production Monitoring and Optimisation System (IPMOS) tool, the Pan-BSP production optimisation can be automated, in real-time. The IPMOS tool performs a high-level production optimisation built on top of existing real-time well production surveillance models, and it dynamically adjusts the system capacity in the event of upsets. In this way, the tool provides day to day advisory of production optimisation during both normal operations as well as during different production upset scenarios, and it also eliminates the need for OCC team to maintain multiple MS Excel sheets/macros to cater for those scenarios. This is a step forward in production system optimisation through digitalisation.