bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &gt;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.