bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimized Coiled Tubing Based Milling of Multiple Composite thru Tubing Bridge Plugs in High Condensate Hydraulically Fractured Deep Gas Wells - A Case Study
Authors: Vijayvargia Utkarsh , Tiwari Shobhit , Anand Saurabh , Sidharth Punj , Sharma Anurag , Janardan Yadav Kumar Manish , Goyal Rajat
Published: November 2016

Raageshwari Deep Gas field is a relatively deep (2800-3500 meters) unconventional volcanic reservoir with pressure and temperature of ~ 5200 psi and ~ 140 degC respectively. Wells were completed as 3-1/2" Monobore producers and plug & perf method was used for fracturing stimulation. 3-1/2" 10000psi rated millable bridge plug was installed immediately after the fracturing stimulation which were then milled by coiled tubing based milling tools to clean up & test all the zones commingled.

During milling of bridge plugs, substantial amount of gas along with significant condensate was produced from the zones, which resulted in vast variance in Coiled tubing circulating pressures and well head pressures. As a consequence, WOB was increased, in an effort to speed up the milling process. Unfortunately this resulted in frequent motor stalling and inefficient milling. Also, managing large amount of produced gas and condensate, along with milled cuttings, sand, gel and water, was an issue with regards to conventional surface equipment’s and frenzied flaring of condensate in vicinity of other gas producing wells.

This paper describes how the bridge plug milling process was optimized over the course of the campaign of hydraulically fractured gas wells. This optimization included all aspects of the milling operation such as, WOB, penetration rate, milling fluid system which facilitated the increase in frac fluid recovery, as well as the differential pressure across the motor. This optimization reduced the bridge plug milling time to between 30 and 45 minutes. It also summarizes the challenges which had to be overcome during the successful implementation of this technique and the lessons learnt in due course of time. This paper also describes the use of a sand catcher along with the conventional surface well testing unit and an inventive surface rig up which not only assisted in perfectly managing the milling cutting, sand, gel and water at surface, while completely eliminating the requirement of flaring the condensate.

The technique helped save about 5% of the total well cost well by reducing the number of days required for milling operations and the associated daily rental of surface well test and Coiled tubing spreads. This technique also ensured minimum flaring of hydrocarbons and faster hookup of wells to production facilities and therefore is strongly recommended in high condensate gas wells located in environmentally sensitive locations with HSE and economic concerns.
A Technical Evaluation of Hybrid Membrane-Absorption Processes for Acid Gas Removal
Authors: Sclierf Michael , Rufford Thomas E.
Published: November 2016

This paper assesses two possible acid gas removal processes for CO2 removal onboard a floating LNG facility: (1) the well-established amine absorption process, and (2) a membrane/amine absorption hybrid process. The assessment considers process and economic aspects as well as sizing due to the on-board application.

Process simulation models of each of the systems were developed in the Aspen Hysys (V8.6) software package. Two different gas fields are assumed with Feed1 containing 10%/0% CO2/H2S and with Feed2 50%/1% CO2/H2S. The feed rate in each scenario was 590,000 Nm3/h and the sweet gas specification was 50 ppm CO2 and 4 ppm H2S. The amine absorption process modelled as the base case was a 50% MDEA solution. The hybrid membrane/amine process featured a polymeric membrane unit implemented as a sub-flowsheet and then the amine unit.

Our results suggest that for a very sour gas feed there may be advantages with a hybrid membrane/amine process that allows the plant weight to be reduced by 80%, volume by 50%, investment costs by 70% and annual operation costs by 40%. The most important disadvantage concerning the hybrid process is the high methane slip which can be reduced by further development of membrane properties and process design. The participation of the membrane unit increases generally with the percentage of acid gas in the feed. If the boundary conditions are comparable to those used in this paper, it can be stated that the CO2 concentration should be at least 10% for a proficient application of a hybrid process.

This study presents models to evaluate novel acid gas removal processes and describes suitable process metrics that could be considered for floating LNG production facilities.
Real-Time Enabled Workflows Help Reduce Drilling Events, Minimize Drilling Times and Anticipate Production in Extra Heavy Oil Asset
Authors: Carrillo Luis A. , Gomez Juan C. , Castaneda Jorge A. , Rueda Rodolfo M. , Urribarri Orlando J. , Neri Victor , Corrales Juan F.
Published: November 2016

At the beginning of 2015 in response to the well construction difficulties faced by drilling companies such as lost circulation, slow Rate of Penetration (ROP) and increasing flat times observed while drilling in an extra heavy oil asset in the Gulf of Mexico, the operator implemented a real-time drilling monitoring center called Centro Inteligente de Pozos (CIP by its Spanish acronym).

The whole purpose of the team and technologies deployed at the CIP is to Anticipate and prevent drilling events; effectively and systematically reduce drilling Nonproductive times (NPT); implement best practices aimed to optimize drilling performance and operate closer to the wells’ technical limits; and accelerate initial oil production by finishing wells before expected.

The CIP solution is comprised of a very well balanced combination of technologies, resources and processes as follow:

Data acquisition, transmission and visualization: Vendor neutral technologies and services are deployed in both ends the rig and the office to enable data collection, integration, aggregation and transmission.

Risk analysis: For each well and prior to start drilling, the CIP team prepares a detailed drilling risk analysis, which includes risk description, prevention and mitigation practices.

Drilling optimization: CIP’s engineers use specialized drilling monitoring software to analyze available data, managed identified risks, optimize performance, and make operating recommendations to exceed performance while drilling within the wells’ technical limits.

At the CIP, the well-coordinated efforts between the operator and the service company in conjunction with the application of efficient processes and innovative technologies, have been cornerstone to reach drilling optimization while minimizing the negative impact of drilling events; making the CIP initiate a success for the operator and service companies.

As a result of implementing the CIP, wells in the Extra Heavy Oil Asset have been drilled in record times. For example, a well that was originally planned to be drilled in 116.7 days was drilled in 89.9 days. This represents total savings of 26.8 rig days (~23% time saved), with a corresponding oil production estimated at 6,000.00 bpd.

Our industry constantly strives to drill faster and safer wells while drilling in more challenging environments. In the author’s opinion one way to achieve this is by adapting classic surveillance procedures with modern workflows based on real-time data and considering relevant analysis such as risk estimation, real-time geomechanics and flat times optimization. The work described in the following pages represents the first successful application of advance real-time drilling monitoring techniques in the Extra Heavy Oil Asset matter of this paper.
Enhanced Deepwater Conductor Jetting Design for East Malaysia
Authors: Prasertamporn Praisont
Published: November 2016

Conductor jetting has been the preferred installation method for deepwater drilling. This type of installation depends on the skin friction between the conductor and the formation, making axial load capacity the critical success factor. Failure of axial load resistance causes well subsidence, incurring high cost in a deepwater environment. In principle, a longer conductor length gives higher axial capacity.

The PSC Company has drilled deepwater wells in East Malaysia and plans to drill more wells in the future. The conductor was designed using the same parameters as the nearby fields and the historical data. In addition, third-party companies normally perform conductor analyses based on the Gulf of Mexico soil set-up rate, which is not similar to East Malaysia. These practices have inadequate theoretical support and could lead to failure.

The paper objective is to analyse the conductor length requirement for East Malaysia with The PSC Company's planned conductor. The analysis includes the conductor length requirements for different well parameters.

The soil profile was derived from the nearby field soil-boring data and previous well parameters to obtain the soil set-up curve. The soil profile was matched with various parameters to analyse the required conductor length. The result describes the significant effect of conductor and jetting bottom hole assembly weight. Higher weight gives more weight on bit, providing high immediate capacity and requiring a shorter conductor. In addition, setting long 20" casing imposes a higher load that requires a longer conductor. However, PAD mud weight and duration before land weight on the conductor do not provide a significant effect. Moreover, other conductor specifications that may be run in the future were analysed, showing the same tendency, where a heavier conductor requires a longer conductor.

This analytical method can be recalibrated for other conductor configurations in the future.

The information contained herein is provided with the understanding that the COMPANY makes no warranties, either expressed or implied, concerning the accuracy, completeness, reliability, or suitability of the information.
Hexapod Pilot Tests Determine the Influence of 3D Motions on the Performance of an Amine-Based Acid Gas Removal Unit Installed on a Floating Support
Authors: Gauthier Perdu , Clément Salais , Vincent Carlier , Claire Prosernat S. A Weiss , Thomas Maubert , Pascal Alix , Manel Fourati , Philippe Béard , Graeme White
Published: November 2016

The objective of this paper is to present new improvements in the knowledge of the performance of an Acid Gas Removal Unit (AGRU) installed on a floating gas production facility, thanks to a R&D program testing the influence of 3D motions and accelerations.

The accurate design of the Acid Gas Removal Unit has a great importance for the profitability and success of a FLNG project. In order to limit both weight and footprint, it shall rely on the lowest possible solvent flowrate and on the minimal and optimum equipment size to treat the feed gas while taking into account motions of the floating support. The proposed paper will demonstrate how a tight but safe design of an amine unit can be proposed thanks to the results of an extensive experimental program.

Total, Prosernat and IFPEN have conducted a four-year R&D program at Heriot-Watt University based on pilot tests aiming at modelization of mass transfer and hydraulics of tilting and moving towers. This program has included the testing of multiple parameters such as liquid/gas flowrates, liquid viscosity, diameter of towers, height of packing beds, packing efficiency. This has been done under various conditions: static tilt, pitch and 3D motions generated by a hexapod robot with six degrees of freedom. The motion conditions tested were similar to those experienced by a column installed on a floating gas production support or on a FLNG.

The collected information on hydraulics and mass transfer showed a significant impact of motions on liquid and gas distribution along the packing beds that can, under conditions of loads of gas and liquids, lead to a significant loss of absorption performances. An in-depth analysis of the large experimental data set with a comprehensive understanding of the phenomena in place allowed the development team to propose a robust model. This model is now embedded in a rated base mass transfer proprietary simulator of AGRU that can predict with good accuracy the impact of motions of the floating support on the performance of the unit.

This paper will present key results accumulated along the program about the impact of motions on liquid/gas maldistribution along a packing bed. It will explain how the accumulated knowledge enables to size tight but reliable AGRU's for installation on a floating support, in the presence of CO2, but also of other contaminants like H2S. The discussion will be supported by comprehensive examples of degradation of the absorption performances on real cases affected by sea motion.
A Study on the Accumulation and Distribution of Condensate Water in a CBM Field Gas Pipeline System
Authors: Guoxi He , Yongtu Liang , Jie Gao , Limin Fang , Liying Sun
Published: November 2016

This paper aims to determine the lowest pigging frequency and to reduce costs of pigging in CBM field gas pipeline system, by simulating the movement of water condensation in the dendritic gathering and transportation pipelines considering hydraulic and thermal character. The water content as a function of time and the distribution of liquid accumulated along the flow line have been simulated. As a result, optimized operation schemes have been proposed. Numerical model was established by considering the influence of temperature, pressure and terrain on gas flow and the saturated water content. The model which was validated by the PipePhase software contains three sub-models, namely the pressure drop model, the temperature drop model and the water film formation model. Then the migration model of water film was established to analyze the accumulation and distribution of condensate water depending on the flow rate and the terrain. Finally, the effects and sensitivity of decisive parameters on the amount of liquid were studied. And the precipitation and distribution of condensate water at the diameter-changing point were analyzed. Thus, total fluid volume and its distribution under different operating and environmental conditions were obtained. It was found that in the entire line, the liquid phase was mostly attached to the pipe wall by liquid film. The liquid film had a slight movement resulting from gravity and the carry of gas phase. Condensation occurred mainly in the first 1/3 length of the pipeline. At the end of the pipeline, the liquid stopped accumulating when the gas temperature kept constant and the pressure drop maintained. More condensate water and longer accumulation region were found in smaller diameter pipeline. And a significantly increased liquid holdup was also found in the diameter-reduced pipeline. Therefore, it is suggested that condensate tank or water drain valve or other facilities should be placed at the low-lying section in the first 1/3 length of the pipeline. The maximum acceptable pressure drop was taken as the target value to determine the longest pigging period under different working conditions. The liquid decreased gradually with the increase of inlet pressure, while with the decrease of temperature. The liquid volume is more sensitive to inlet temperature, and then ambient temperature, inlet pressure and flow rate. Thus it is suggested that the outlet pressure of compressor should be increased or an air cooling device should be installed.
Performance and Calculation Method of Steam Chamber Overcoming High Water Saturation Intervals during SAGD Process
Authors: Yang Renfeng , Zhang Jinqing , Yang Li , Chen Han , Tang Shasha
Published: November 2016

Many researchers study on the analytical model to predict chamber-to-reservoir interface shapes, production rates and oil-to-steam ratios during SAGD (Steam Assisted Gravity Drainage) process. But most studies are based on homogeneous reservoir models. Heat energy is transferred from steam to reservoir by conduction and convection, but heat transfer by convection is not considered in the classic SAGD mathematical models, especially when encountering the high water saturation intervals. And there was no analytical model or approach to analyze the performance of steam chamber overcoming high water saturation interval except the time consuming reservoir simulations.

The function of steam chamber rising height versus time was analyzed, thus the time duration before steam chamber invading the high water saturation intervals could be calculated. Then the relative roles of convective and conductive heat transfer at the edge of steam chambers were studied. A new calculation method was proposed to calculate the influence time of overcoming high water saturation intervals. According to the formation parameters, fluid properties and thermo-physical parameters, the influence time of overcoming high water saturation intervals could be predicted for other horizontal well-pairs, which has been proved to have high accuracy.

The newest significant finding is that convection can transfer a relatively large amount of heat at the edge of a steam chamber, but temperature increase because of convection is minor which could be neglected and the functional relation remains the same but the coefficient decreases. Meanwhile, a variable associated with vertical position of the high water saturation intervals is taken into account which could be obtained from the logging data. The value of the coefficient becomes smaller while the steam chamber invading high water saturation interval, because the high water saturation intervals rapidly halt the vertical growth of the steam chamber and spread the chamber laterally. The proposed method has been certified using temperature data from many wells and several reservoirs. The results demonstrated that the proposed new method works satisfactorily.

The novelty of the proposed method is in the ability to forecast the performance during steam chamber overcoming high water saturation interval in SAGD without time consuming reservoir simulations, which has been proved to have high accuracy.
Hydraulic Fracturing of Ultrahigh Stress Tight Oil Reservoir - A Case Study of Yumen Oilfield in China
Authors: Yi Peng , Dingwei Weng , Yun Xu , Liwei Wang , Yongjun Lu , Zhanjun Liu , Xiang Peng , Jiong Meng
Published: November 2016

This paper provides a case history of the first massive hybrid hydraulic fracturing in k1g1 tight oil formation of Yumen Field in China. Stimulating k1g1 formation is facing at least three difficulties: (1) deep depth (≥4700m TVD); (2) high treatment pressure(≥95MPa); (3)high fracture closure stress(≥100MPa), and fracture propagation gradient(≥0.0252MPa/m). There is oil and gas showing between 4640-5360m among wells in this region. These are tight sandstone highly laminated with mudstone, and the expected permeability was between 0.01 to 1mD, average porosity was 8.69%. The first a few stimulation treatments attempted in k1g1 formation nearly 10 years ago did not get good enhancement due to small stimulation volumes constrained by high treatment pressure and ultrahigh closure stress.

This paper analyzes the initial fracture treatment problems integrated with fracture modeling studies and provides a detailed discussion of formation characterization, rock mechanics, fracturing fluid and fracture design issues. And these studies were used to improve the stimulation strategy for future wells and help place more proppant volumes. Optimization of low-concentration HPG fracturing fluid (0.35%HPG, reservoir temperature≈110°C) and clay stabilizer were also conducted to reduce the damage to the formation which is more sensitive to it because of its low permeability and tiny pore throats. Proppant placement was achieved by using large volume slick water with multiple proppant-slug in low concentration and tailed in high concentration proppant with cross-linked gel fluid.

Yumen oilfield, as the pioneer in China's petroleum history (the first oil well was found there, so did the first well stimulated), is facing the huge challenge of production decline after almost 70 years’ continuous production. With the success of well CSL313 and CSL703, consequently k1g1 tight oil formation with 700m interval would be a good candidate for the succeeding resources. And the stimulation method described in this paper can be applied in other wells to ensure essential success of placing the designed proppant volumes and achieving aggressive stimulated intensity.
Successful Deployment of Tractor Conveyed Perforation in a Horizontal Well: Designing, Execution, Results and Lessons Learnt
Authors: Goenka S. K. , Goyal I. , Pandey N. , Kothiyal M. D. , Shah A. , Parasher A. , Vermani S. , Pinto T. , Nayak J.
Published: November 2016

Well X is a horizontal oil producer in AB-3 formation of the B field situated in the RJ-ON-90/1 block of Western India. Intervention in a horizontal well is inherently challenging, but the complex completion equipment of this well imposed additional challenges due to multiple ID changes along the well bore. The 8.5" OH section is completed with Inflow Control Device (ICD) screens and Swell Packers, middle completion consists of Packer and a Reservoir Control Valve (RCV) section set in the 9-5/8" production casing. Finally with 4.5" production tubing – and the production packer, upper completion was lowered but end of tubing was lying 8 m above the RCV section exposing 9-5/8" casing section also during any intervention.

After the initial completion when well was put online, it couldn’t flow naturally and was activated with nitrogen. Post activation it was observed that a well with 500 m of clean sand along the lateral section and productivity index (PI) of 150 b/d/psi was flowing with a PI of ~ 10 b/d/psi which also was not sustained and well was put on artificial lift. After attempting various stimulation techniques and correlating with offset wells, it was decided to perforate the screen section of the horizontal.

E-line conveyed Tractor assisted gun deployment system was selected to access the high angle well bore and perforate the screens. Apart from high deviation, the intervention unfriendly completion posed a major challenge to successfully RIH and POOH without a stuck tool or a tool lost-in-hole (LIH) situation. Extensive job planning, designing, and intervention modeling was completed before attempting the operation. The perforation job was carried out as a pilot test in 6 m of the 500 m OH section and resulted in ~ 1500 bopd of incremental oil in the initial well production. Analysis of the entire pilot project from the economics, technology and opportunity triangle, demonstrated the value of the technology and its usefulness in the future.

The paper endeavors to discuss the entire case while detailing the salient features like candidate selection, job designing and planning, challenges involved and lessons learnt during the successful execution of the intervention, also making it first of its kind horizontal perforation in the India. The learning and information shared will surely be useful in future to all such planned interventions into a high angle well especially during critical jobs like perforation.
Exploratory Drilling in Severely Ballooning Formation - Use of Best Drilling Practices and Real Time Monitoring for Low Cost Mitigation
Authors: Golwalkar A. , Lang C. M. , Doodraj S. , Singh A. K. , Manoranjan K. , Pandita A.
Published: November 2016

Wellbore ballooning (or wellbore breathing) is a pertinent drilling issue in exploration wells where the formation lithology, geo-mechanics, pore pressure and fracture pressure regime is not fully understood. This phenomenon is generally observed in formations with micro-fractures. While the pumps are on the ECD is just sufficient to open up the natural micro-fractures allowing the mud to enter the formation. As the pumps are switched off the dynamic pressure effect is lost and the static mud weight is insufficient to keep the fracture open, resulting in the mud lost in the formation to flow-back as the fracture closes. A flow back of mud is observed on the surface with pumps off, which can be misinterpreted as wellbore influx or kick.

Misinterpreting a wellbore ballooning phenomenon as a well kick can lead to the application of standard well control procedure which can aggravate the problem and may have severe implications even to the extent of well failing to meet its objective and being prematurely abandoned.

This paper presents case studies of two wells, viz. NJ North East-1 and Raag Deep Main-1, drilled by the operator in the same block. Severe ballooning was observed in the first well wherein delayed identification of the phenomenon resulted in high NPT and consequential cost impact. The lessons learnt from this experience were implemented in the second well with similar ballooning issues, along with close real-time well monitoring while drilling resulting in smooth drilling operation and successful achievement of objectives as per plan This paper also summarizes suitable in-field drilling practices to be adopted and implemented to mitigate wellbore ballooning, which can be a low-cost alternative to expensive technologies used to counter this phenomenon.
Experimental Study on Injection Strategy of CO2 Near-Miscible Flooding in Low Permeability Reservoirs with High Water Cut
Authors: Chen Hao , Yang Shenglai , Liu Jianchun , Zhang Xiansong , Mei Yuan , Li Xiaofeng , Li Ying
Published: November 2016

Lack of gas source and poor physical properties of oil are two key problems for the application limitation of CO2 miscible flooding in China. However, in Jilin oilfield, the discovery of natural gas reservoir with different CO2 content (5%-98%) make it possible, especially for some low permeability blocks. MMP determined by slim tube test is 23.5MPa. Reservoir pressures after prolonged waterflood development are maintained at 23 MPa to 24.5 MPa. Thus, CO2 near miscible flooding for these oilfields is of great potential. Advanced CO2 injection is proposed for the undeveloped blocks and WAG is proposed for the high water cut blocks.

Long core (~1m) test shows that CO2 injection before oil production can ease the fast decline of reservoir pressure for this low permeability reservoir. Oil and CO2 has more time to contact then miscibility can be fully developed, fingering improved and oil damage of depleted development can be avoided. Recovery incremental is about 6.7%.

In addition, injection rate, injection opportunity, injection pressure, water gas ratio (WGR), water cut, gas oil ratio and oil recovery were all considered to optimize the parameters of WAG in waterflooded reservoirs with different water cut (30%, 50%, 75%, and 90%). Results show that the optimum WGR is 1:2, and the optimum gas slug is 0.1 PV. Channeling and bypassing were concluded to be the main reason for the early breakthrough and low oil recovery considering the low transmissibility. However, slow gas injection rates, may fail to maintain pressures and oil rates. Thus, the optimum injection rate is 0.05 cc/min for both water and CO2. Also, it was found that the earlier the WAG conducted, the faster the water cut and oil production response, and the more obvious the water cut decline and oil recovery increase. Results show that more than ~30 % of the residual oil after water flooding could be recovered, which indicates that CO2 near miscible flooding, including advanced CO2 flooding and WAG, could be feasible in some blocks of this low permeability reservoir.

The results of this study should contribute to our understanding of the mechanisms and injection strategy of CO2 near miscible flooding in water drive reservoirs and support the ongoing research, development and application of CO2 tertiary oil recovery process in Jilin Oilfield.
Multi-Attributes Analysis and Neural Network: A New Approach of Reservoir Characterisation in Thap Raet and Greater Sirikit East, Phitsanulok Basin
Authors: Suwatjanapornpong Supannika , Jaruwattanasakul Chalong , Kreeprasertkul Kritti , Suwanruji Padsakorn
Published: November 2016

Thap Reat (TRT) and Greater Sirikit East (GSE) are mature oil fields located in the Phitsanulok Basin, in central Thailand. Structural play types are the main contributors to maintain high production of this field. Nevertheless, stratigraphic play types have become more interesting in these to identify new opportunities in undrilled areas. The major challenge of these stratigraphic plays is understanding the depositional model and facies distribution, which with conventional techniques may not be able to properly portray the subsurface framework. The combination of statistical methods along with multi-seismic attributes analysis will help characterize the reservoir complexity.

This study aims to predict reservoir properties by utilizing a combination of well and seismic data through statistical analysis. There are three main steps in this study. Firstly, several seismic attributes are derived from seismic data and then, using statistical methods select the best group of attributes. After that, the neural network algorithm is used to improve the correlation between well log and seismic attribute through a non-linear relationship. Finally, the result has to be validated by correlation error and then applied to a seismic cube in order to predict reservoir properties from multi-attributes.

From available data, there are many types of log can be used in prediction such as P-wave velocity and porosity. Each predicted log shows a good relationship between seismic traces and seismic attributes. This study will use porosity logs to predict porosity from the seismic cube. To get the best result, the accuracy of synthetic seismogram is very important to define the analysis window. After the results of multi-attribute analyses are evaluated by an automated blind test, the operator is created internally and then applied to an entire seismic cube. Nevertheless, not only are the multi-attributes used to predict the reservoir characteristics, but also a neural network is able to improve the correlation value by its non-linear relationship. As a consequence, the new operator updates the prediction in 3D volume. From geological interpretation of the results, the stratigraphic features are better illustrated and thin reservoir trends can be predicted. Finally, it can be concluded that the statistical method in combination with seismic data works well to characterize thin reservoirs in a mature oil field. Additionally, from a statistical viewpoint, the higher accuracy of valid input data leads to a more reliable outcome.

The study supports depositional models serving stratigraphic play exploration. The outcomes can be used in the further work in both exploration and development. Predicted reservoir connectivity can be used to support secondary and tertiary recovery. Moreover, it is more efficient and decreases time-consuming conventional attribute analysis.
Predicting the Location of Multiple Volcanic Eruption Vents for Resolving Facies Heterogeneity and Distribution Patterns within Extremely Challenging Gas-Bearing Underwater Volcanic Deposits of Japan
Authors: Kar S. , Kodaira C. , Irie S. , Li S. , Morelli C. , Gong H.
Published: November 2016

The current study was carried out in one of the most economically viable gas-bearing reservoirs in Japan, the Minami-Nagaoka volcanic field, located to the southwest of Nagaoka. Petroleum deposits occur in deep-seated underwater volcanic rocks of Miocene age, and these deposits contribute significant amount of Japan's total natural gas production. Because of the steep rise in domestic gas demand, re-examination of the existing data sets was performed to understand the geological reason for the extreme lateral facies variation, the complex facies distribution pattern, and production uncertainties. The study revealed a very interesting geological phenomenon of multiple eruption vents that is responsible for the complex facies association and distribution pattern within the study area.

A robust workflow was designed through maximizing utilization of existing high-resolution datasets to solve the current challenges in the field. At the beginning of the workflow, different complex underwater volcanic facies were recognized in image, core, and log data. After volcanic facies reconstruction in each well, facies associations and their distribution pattern across wells were visualized. Finally, using background geological knowledge and well-based facies identification and correlation, a model with multiple volcanic eruption vents was conceptualized within the study area from north to south. In addition, the probable location of different drilled wells relative to the location of the multiple volcanic vents was defined based on the facies assemblages of each well.

The present work demonstrates a unique way to conceptualize and model the paleovolcanic eruption events within a volcanic field. Understanding the paleovolcanic eruption model is key for proper understanding of the facies distribution pattern and facies variation across wells and for finding the best drilling location for hydrocarbon exploration wells. It was observed that the facies with a high amount of lava are located close to the volcanic vent, and wells with a higher amount of brecciated facies are located farther from the volcanic vent. Another type of facies, which is unique for underwater volcanism, is the hyaloclastite (glassy type) facies; this facies is located towards the margin of the volcanic vents. In addition, lateral facies variation was clearly understood after visualizing the eruption model, which was no possible prior to the present study.

The current workflow demonstrates a novel approach for better understanding the paleogeological condition for a unique type of gas-bearing submarine volcanic reservoir, which is a very rare example in the present oil and gas industry. The technique in this work represents a new way of looking high-resolution well data for geological modeling and evaluation of any volcanic field.
Towards a Better Selection of Foamers for the Deliquification of Mature Gas Wells
Authors: Omrani P. Shoeibi , Shukla R. K. , Vercauteren F. , Nennie E.
Published: November 2016

In mature gas wells which are suffering from liquid loading, foamer injection is employed to mitigate the liquid loading and increase the stable gas production. Evaluation of the foamers performance and their chemical stability prior to their injection in the wells is of great importance. For this purpose, laboratory tests are performed to give an indication on the foamers performance. In this study, we focus on the effect of hydrocarbon fractions (condensate/brine ratio) and temperature (up to 120 °C) on the foamer performance in laboratory tests. A modified version of the Bikerman gas sparging setup was designed to allow for tests at higher pressures (up to 15 barg) and temperatures (up to 150 °C), compared to the currently available test setups. Three tests were performed to quantify the foamer performance; foam buildup, collapse and liquid carryover tests. The results indicated that higher hydrocarbon fraction significantly reduces the foam formation rate and liquid unloading capabilities. The current work highlights the importance of using a representative brine-hydrocarbon ratio for foamer evaluation tests. Additionally, on the effect of temperature, three different foamers were studied and the results showed a significant negative influence of high temperature on the foamer performance. It was observed that the effect of temperature on foamer performance is surfactant dependent. Therefore, it is essential to evaluate foamers in the laboratory tests at the temperatures as close as possible to the field (downhole) temperature.
Estimation of Fluid-Fluid Contact and the Transition Zone: A Case Study of Low Contrast Resistivity Zone
Authors: Akbar M. N. Ali , Permadi P.
Published: November 2016

Determination of a fluid-fluid contact and the transition zone is a crucial problem in formations having a low contrast resistivity (LCR) characteristic. High reservoir heterogeneity even makes a serious problem when the contact is not encountered in the existing wells drilled. Improper use of capillary pressure data may lead to severe errors in estimating both the contact and the transition zone.

This paper presents a technique to determine a fluid-fluid contact by maximizing and integrating geological and engineering data available such as well logs, routine and special core analysis (SCAL), and flow test data. Integration of all the data leads to establishing rock types along the interval of interest and developing the corresponding capillary pressure data needed. Establishment of rock types is shown to be of importance because SCAL data are rock type dependent. Flow test data and relative permeability ratio data are used to determine water saturation at the tested interval.

Two well cases of a LCR zone are considered in this study. All the data needed are available, except that capillary pressure data are limited. The rock type model based on the core analysis data available enables us to develop additional capillary pressure curves as needed. Combination of log responses and routine core data are used to predict permeability. The rock types are then distributed in the well within the tested zone. The oil-water contact (OWC) estimated for each of the zones by applying the technique proposed is significantly deeper than that previously determined using resistivity logs. The water saturation distribution within the transition zone is controlled by the distribution of rock types. When the previous corresponding OWC in each zone is used, it is shown that the calculated Water Cut much higher than the actual data. This demonstrates that the electric log-based OWC is too pessimistic.

In conclusion, the LCR zone under the study needs an integrated solution. The proposed technique offers a theoretically sound solution for estimating a fluid-fluid contact and water saturation distribution in the transition zone. It can be applied to common problems of fluid-fluid contact estimation. A procedure to overcome limited SCAL data is provided.
CCS- A Bitter Past or a Prospective Future
Authors: Khan S. , Ali S. F. , Athar K. S.
Published: November 2016

Carbon Capture and Storage (CCS) is indeed a very effective technology in reducing the CO2 concentrations from the atmosphere and possesses massive potential for mitigating climate change. Over the years CCS processes has evolved, however, it is still believed to be in initial phase and appears as a new idea to many under developed countries. Today CCS appears as the only applicable solution to reduce Gigatonnes (Gt) CO2 emissions besides burning the fossil fuels for energy. The application, however, is not as straightforward as it appears. The high costs and potential risks associated leaves the vision of mitigating climate change through CCS under obscurity, thereby, making the future of CCS a bit vague.

This paper aims to project the near future of CCS by the analysis of present CCS prospects, CO2 capturing and storage processes, risks and problems associated, and more importantly the economics encompassing a CCS project. The paper begins with the brief overview of Carbon Capture and Storage (CCS), followed by a comparison of different capturing processes, storage mechanisms, potential problems and risk complications; a comparison of renewables in contrast with CCS is provided. Lastly, the economics and costs of present CCS prospects in different parts of world are discussed. All work is done to make future inferences about CCS, how this evolving technology can be made economically feasible also, and what will be the impacts and consequences on the climate change (increasing GHG concentrations) had no government, public and private sectors consideration been given to CCS, and will the environment be ever safe without CCS.
Evaluation of Three Phase Relative Permeability Models for Simulating Immiscible WAG Injection in Carbonate Rocks
Authors: Al-Nuaimi Latifa , Shahrokhi Omid , Sohrabi Mehran
Published: November 2016

Three phase relative permeability models are used widely by reservoir engineers to investigate the performance of petroleum reservoirs, in particular, for designing gas injection strategy or WAG injection projects. However, there are concerns about the validity of the existing models and the reliability of predictions made by these models.

In this paper, we have assessed the performance of some of these models for WAG injection in carbonate rocks by comparing the prediction of the models with the results of coreflood experiments performed under reservoir temperature and pressure.

Two phase relative permeability results were obtain from history matching the experimental data by using our in-house history matching software. The estimated gas/oil and water/oil relative permeability curves were then used to simulate the results of immiscible gas and water injection under different injection strategies using different three-phase kr models. The results of these simulations were compared with experimental results.
Identifying Deep Sweetspots: Seismically Constrained Reservoir Quality Prediction Offshore Brunei
Authors: Gelinsky Stephan , Kho Sze-Fong , Espejo Irene , Keym Matthias , Näth Jochen , Lehner Beni , Setiana Agus , Esquito Bench , Jäger Günther
Published: November 2016

Prospects below or near shallower producing fields can be economically attractive yet also risky since reservoir presence may be uncertain, reservoir quality can be poor, and high overpressure and temperature can make drilling and logging deeper prospects difficult. Systematic integration of relevant subsurface data from thin section to basin scale allows to seismically identify reservoir presence, and to predict reservoir quality for applicable rock types via burial histories. On an intermediate well log to seismic scale, a predictive rock physics modeling approach links reservoir and seal rock properties to seismic amplitude data to polarize the prospect's geologic ‘probability of success'. Particular challenges in the offshore Brunei study were very fine-grained deposits and non-vertical tectonic stresses associated with compressional settings. Both make porosity predictions that leverage complex burial histories rather than relying on extrapolated depth trends quite challenging - yet the integrated approach remains the best option to identify deep reservoir quality sweetspots that a favorable stress and temperature history may have preserved for certain reservoir rock types in certain locations.

The prolific petroleum system offshore Brunei features two major sediment fairways, the Baram and Champion river systems, and a variety of depositional environments, ranging from high NtG topsets inboard over shallow marine slope settings to deepwater turbidites outboard (Gartrell et al., 2011). Across Brunei Darussalam, the systematic ‘Earth-Model’ study, jointly undertaken by BSP and SDB, defined gross depositional environments (GDE maps) and calibrated a 3D basin model. The study leveraged newly reprocessed Broadband seismic data that over large areas had improved imaging of the subsurface. Complementing this regional geologic evaluation with the goal to assess deep reservoir quality, in the here presented study multiple reservoir and bounding mudrock facies were identified and their composition and texture determined from thin sections. Present day porosity and cement volumes were then calibrated and blind tested with burial histories from the basin model. The reservoir quality calibrations will be applied to predict expected present-day prospect reservoir quality. In parallel, sand and shale acoustic properties were calibrated for applicable rock types to allow for quantitative seismic interpretation of reservoir-seal reflectors and to establish the regional ‘amplitude floor'.
A Case Study on the Shwe Gas Field Development Completion in Myanmar—From Design to Installation
Authors: Park D. , Song I. , Bae Y. , Kikuchi M. , Ling J. P. , West S. , Yap J. , Ridho M.
Published: November 2016

This paper covers the strategies implemented when completing the Shwe gas field in Myanmar. The field, operated by Posco-Daewoo, has been in production since 2013. We present our study and evaluation of the reservoir, integrated completion design, operational challenges, and production performance of the wells.

The project began when Myanmar was subjected to economic sanctions and Myanmar is considered a remote location with quite limited infrastructure, so there were many challenges on the logistics front. The goal of our completion design was to complete the unconsolidated reservoir with either openhole gravel pack (OHGP) or cased hole gravel pack (CHGP), depending on the tendency for water production. The upper completion was designed to optimize gas production. Permanent downhole gauges (PDHG) were installed to monitor the reservoir pressure and temperature.

As part of the development program, eight gas wells and one condensate disposal well were drilled and completed from 2013 to 2015. –Logistics and preparation, key contributors to the success of these installations, were supported from Singapore with a limited transit time to the platform, which meant that turnaround time was closely monitored to meet delivery each time.–The lower completion project in the 9 5/8-in casing consisted of four OHGP wells and four CHGP wells. Screen type and size, and gravel type and size were determined using particle size distribution studies with core samples and software simulation. Findings were then further verified with extensive lab testing.–To achieve minimal skin and damage for the gravel pack (GP) carrier fluid, a nonpolymer fluid was used for CHGP and OHGP. Although a breaker was incorporated into the carrier fluid for OHGP, a filtercake breaker was pumped afterward for maximum cleanup. As for CHGP, the wells were acidized prior to gravel packing. Breakers for the carrier fluid were displaced pre- and post-GP.–For the upper completion, five wells with 7-in production string and three wells with 5.5-in production string were completed. After landing the completion string, a formation isolation valve (FIV) was cycled open, followed by well testing. The subsequent pressure matching we performed confirmed that minimal skin and damage were achieved.–We achieved and exceeded all the objectives set for the campaign in terms of HSE performance, operational efficiency, production rate, and sand-free production.