bluuebunny/crossref_metadata_2025 huggingface dataset:
Hybrid Solution Improves ROP and Borehole Quality in Challenging Large Diameter Holes
Authors: Omar Marwa , Valbuena Franklin , Abdelhamid Atef , Agawani Waleed , Taha Mohammed , Saleh Khaled , Baqer Yousef , Nath Saswata , Abbas Moufid
Published: October 2015

In the prolific Burgan field, South East Kuwait, new well profiles are being employed which require the 16 inch hole section to be drilled deeper. This new well profile requires drilling through interbedded abrasive sandstones and sticky shale which were previously drilled in 12 ¼ inch hole size. Drilling becomes increasingly challenging using larger diameter bits where torque fluctuations, down-hole conditions and durability limit performance. As the casing profiles changed, each section's drilling solution was revisited as drilling dynamics and performance diminished drastically when drilled in the larger hole size. What was once a viable solution to drill the section in 12 ¼ inch becomes no longer suitable when drilled in 16 inch. The purpose of this paper is to demonstrate the engineering analysis for large diameter hole application and the selection of an optimized hybrid drill bit design, roller cone combined with Polycrystalline Diamond Compact (PDC), to maximize drilling performance where standard PDC or roller cone bits alone fail to provide an optimal solution.

The 12 ¼ inch section was typically drilled using a rotary bottom hole assembly with a roller cone bit or using a performance mud motor with a PDC bit. Drilling parameters were reduced in the upper layers especially with PDC bits as they involve sticky shale which can induce bit balling. While in the lower layers the abrasive formations tend to wear down roller cone bits.

Combining the benefits of both bit types, a 16 inch hybrid bit was proposed to answer the challenge of drilling the section as fast as a PDC bit while providing the stability, torque control and smooth hole condition generated by a roller cone. Selecting an appropriate hybrid design to match the application resulted in an initial trial of a durable hybrid bit that finished the interval with virtually no wear on the bit and significantly improved borehole quality. The second trial of the hybrid bit with a modified, more aggressive design approximately doubled the ROP of a PDC bit while maintaining a smooth hole profile and minimizing torque.

PDC bits generally provide faster rate of penetration than roller cone bits while generating higher torque fluctuations as they drill by shearing bottom hole formation. Due to their high torque demands, PDC bits require an additional mud motor to drive them efficiently in larger hole sizes. Roller cones crush and gouge the bottom hole formation and due to their mechanical rollers result in reduced reactive torque and a smoother hole profile. Hybrid drill bit technology proven the capability of achieving the benefits of both designs in specific selected applications.
The Implementation Phase: Improve the Intelligent Field Real-Time Data Reliability Using Key Performance Indices
Authors: Al-Amer Abdulrahman A. , Al-Naser Naser , Al-Kadem Mohammad S. , Abo Khamseen Mohannad A.
Published: October 2015

Nowadays, there is a massive amount of real time data that flows from the intelligent sensors to the petroleum engineers desktop. High quality data is required to utilize in production workflows and technical studies. The reliable transmitted data as real-time pressure and temperature will enable the petroleum engineer to track the performance of the wells, generate production strategies, and monitor the real-time production, and a lot of more workflows remotely from his/her desktop without jeopardizing the well condition or the reservoir structure.

In Saudi Aramco, monitoring the quality of real-time data for validity, accuracy, consistency and intelligent field equipment integrity is accomplished via the utilization of state-of-art intelligent field data health monitoring platform. It provides an alarming system of problematic data and equipment. It also generates a daily data quality report for a specific intelligent field data transmission node.

This paper is a continuation of the technical paper titled "Intelligent Field Real-Time Data Reliability Key Performance Indices" (IPTC-17997-MS, Kuala Lumpur, Malaysia, 10-12 December 2014). This paper will highlight the tangible benefits of implementing the new monitoring platform in four different examples that show the importance of having intelligent field data reliability tracking solution in each oil and gas company to improve the data reliability. Making the decision process accurate, through utilizing an advanced automated data management platform, is crucial butreceiving real-time quality data is essential.
Identification and Characterization of High-permeability Zones in Waterflooding Reservoirs With an Ensemble of Methodologies
Authors: Ding Shuaiwei , Jiang Hanqiao , Wang Lei , Liu Guangwei , Li Ning , Liang Bin
Published: October 2015

Efficient management of water flooding oil fields requires an accurate characterization of high-permeability zone, which evolves from long-term water flooding, as sand production and clay erosion have contributed to the variation of formation structure. These zones are a subject of concern for reservoir engineers, as they lead to early water breakthrough in oil producers and uneven sweep around water injectors. The objection here is to use an ensemble of methodologies to determine the level and characterize high-permeability zones in waterflooding reservoirs.

X oilfield in western North China has entered into a high-water-cut stage and high-permeability zones are increasing serious with the development of the oilfield. All the parameters are obtained from reservoir numerical simulation model after automatic history matching (AHM) using ensemble Kalman filter (EnKF) with covariance localization. The updated reservoir model is used to characterize the high-permeability zones in the reservoir. Then, theory of logical analysis (TLA) is used to select the static and dynamic parameters which are most correlated with the formation of high-permeability zone, for there are many variables involved in the evaluation on determining high-permeability zone. Extensive laboratory testing and dynamic analysis prove that wells that tend to form high-permeability zone have certain similarities on geological structure and dynamic performance, thus the reservoir can be graded into three types of absence of high-permeability zone, presence of light high-permeability zone and presence of large high-permeability zone according to fuzzy C-mean clustering algorithm (FCMCA). This results were verified by a typical well group through interwell tracer and historical water injection profile. This methodology is also useful for the design of water shutoff and profile control by polymer injection at the high water-cut stage of the oil field.
Case Study of Fine Geological Modeling for Mishrif Carbonate Reservoir of H Oilfield in Iraq
Authors: Limin Zhao , Duan Tianxiang , Han Haiying , Xu Jiacheng , Guo Rui , Zhu Xiang , Liu Lei
Published: October 2015

Accurate geological characterization for complex carbonate reservoirs plays an important role in guiding the optimal oilfield development. Mishrif Formation of H Oilfield in south of Iraq is the most important target among several Cretaceous oil-bearing carbonate formations due to the high OOIP proportion. It is composed mainly of bioclastic limestone with multiple pore types. It is massive reservoir with medium porosity and low permeability. The great variation of vertical and lateral reservoir quality leads to poor relationship between porosity and permeability which brings great challenge in reservoir characterization and favorable area identification. This paper presents the comprehensive reservoir evaluation and characterization in combination of all data available. The sedimentology and stratigraphy are reviewed in terms of depositional environment and lateral stratigraphic correlation. The variability inherent to the depositional mode and digenesis leads to complex reservoir geometry and pore types. Rock typing is examined based on core measurements and well logs to get the improved correlation coefficient between porosity and permeability. Neutral network method is used to propagate the rock types to un-cored wells to get the accurate permeability estimation. Facies model and rock type model are built constrained by the seismic inversion reservoir prediction results which provide crucial information on carbonate proportions distribution, especially in areas with low well control. Permeability model is generated constrained by rock type and porosity which can indicate the reservoir flow capacity. Based on the integrated reservoir model, horizontal wells and multilateral wells for Mishrif Formation are proposed and optimized in the good reservoir quality area. The high individual well production rate verified that the well placements upon fine reservoir modeling are successful.
Lessons Learned From a Subsurface, Well Completion, and Hydraulic Fracturing Perspective for a Multiwell Liquid-Rich Resource Play in West China
Authors: Zhang Jing , Jiangwen Xu , Liu Yuan , Judd Tobias , Liu Hai , Li Niu
Published: October 2015

There is a variety of well completion and hydraulic fracturing technologies available for liquid-rich resource plays. The industry approach tends to include horizontal wells with multiple fracturing treatments, and depending on the selection criteria, it may result in certain operational efficiency and production enhancement advantages. Thus a comprehensive strategy to properly select the applicable technologies is based upon geology, subsurface understanding, well design, production expectations, and operational readiness.

Following the successful completion of the exploration phase of the Jimusaer project located in the Jungger Basin of West China, a pilot drilling program was initiated that included multiple horizontal wells being drilled from selected well pads. The completion and fracturing operations were completed in two phases that included the evaluation of different completion technologies, placement methodologies, and fracturing designs being optimized for later wells based on initial well results. The initial phase was done in 2013 and included 62 fracturing stages on four wells completed with an openhole sliding sleeve system. The six remaining wells were completed in the following year which involved 130 stages. Besides optimizing the fracturing design approach, it included a shift towards cased-hole completion techniques involving the plug & perf approach.

Overall technical understanding and recognition of underlying trends were improved by reviewing the abundance of reservoir and well data from the 10 horizontal wells completed to date. Additional insight was obtained by the incorporation of hydraulic fracturing monitoring measurements with flowback performance and monitoring of individual fracturing stages through the deployment of unique chemical tracers. Despite the variation in completion and fracturing technology, reservoir understanding and well placement were the primary factors impacting individual well performance. In conclusion, the overall pilot project was designed to reduce the uncertainty in key reservoir parameters, test various completion/drilling technologies, and assess full-field development issues while moving towards fairway sweet spots.
Offshore Coiled Tubing Interventions Maximized the Value of Watered Out Mature Fields Using Selective Water Shutoff Treatments With an Organic Crosslinked Polymer in a High Temperature Sour Well
Authors: Beltagy Ahmed El , Taha Islam , Shawky Ahmed , Gaber Nabil Salah , Elwan Mahmoud Attia
Published: October 2015

Saqqara is a very challenging field in the Gulf of Suez in the Red Sea area, producing from the deep sandstone Jurassic formation. This formation can sometimes be watered out, with a combination of high H2S and CO2 levels in the production. High sand quality has developed high horizontal and vertical permeability, which challenges any water shutoff treatment placement.

One of the critical measures of success in water shutoff treatments is selective zonal shutoff across an existing hydrocarbon zone. It was challenging to select a deep penetration polymer to treat the selected zones, as it must resist high temperature degradation (321°F), particularly in existence of high concentrations of H2S. Different water shutoff (WSO) treatments were considered, but selecting an organic crosslinked polymer (OCP) gave the best lab results because of its stability in high temperature conditions.

Placement and isolation techniques were challenging, particularly with the existence of multiple zones of interest. Therefore, coiled tubing (CT) well intervention methods were selected for best placement without resorting to a more expensive workover option.

The results of the treatment were designed toward the sustainable production of these kinds of mature watered out fields. The treatment succeeded by reducing produced water from almost 2,300 BWPD down to almost zero BWPD.

This process allows the operator to increase the drawdown value, which strongly affects the BOPD value compared to the initial watered-out condition. The treatment maximized the value from mature fields revitalization, redevelopment, and end of field life planning.
Efficient Sampling Scheme for Uncertainty Quantification Using PCA
Authors: Kang B. , Lee K. , Choe J.
Published: October 2015

Reliable uncertainty quantification requires a large number of simulation models and huge computation time. It would be preferable for simulation time to be short to apply in real field management. Therefore, our aim is to reduce the total simulation time as well as predict future reservoir performances reliably. In this study, we propose a novel method to sample ensembles using principal component analysis (PCA) and K-means clustering.

We construct a two-dimensional plane on which initial ensembles are projected with their principal characteristics. The plane is made by eigenvectors of the data corresponding to the largest eigenvalues. Divided into 10 groups using K-means clustering, we choose the same number of ensembles from each group. Clustering helps to sample unbiased ensembles. It can be a biased sampling without the clustering procedure.

We compare uncertainty ranges using 100, 50, and 20 sampled ensembles with those of initially generated 400 ensembles. Compared to the non-sampling case, the results with the proposed method show comparable quality in predicting oil and water productions on a synthetic reservoir. Uncertainty ranges with the sampled ensembles have similar trends with the base case and 100 ensembles show an optimal results, considering both prediction quality and total simulation time. We reduce 94.8% the total computation time at maximum as well as maintaining uncertainty ranges from the 400 ensembles. The proposed sampling method takes only few seconds so that it suggests powerful applications for efficient history matching and helps fast and reliable decision making.
Inflow Performance Relationship correlation of 2 Phase CBM Reservoir
Authors: Sugiarto Isan , Mazumder Saikat , Wittemeier Roxanne , Sharma Vikram
Published: October 2015

The inflow performance relationship (IPR) for a coalbed methane (CBM) reservoir is relatively complex as the production behaviour is different from conventional gas wells, as gas in coal is stored by means of adsorption. Most often coal reservoirs are relatively under saturated, meaning the pressure in the reservoir needs to be substantially depleted prior to gas desorption. Gas from coal is produced at relatively low reservoir pressures, thus requiring the pseudo pressure function to be included in any deliverability calculations. A two phase flow system in a coal reservoir adds to that complexity as relative permeability, reservoir geo-mechanics and saturation needs to be taken into account within the IPR correlation. The IPR correlation for coalbed methane wells is an important part of any well performance optimisation and nodal analysis.

A simplistic IPR correlation for multi-phase coalbed methane wells was generated based on the history matching of field production data. The correlation has been tested both for a multi seam completion in the Surat Basin and for horizontal wells in low permeability coals within the Bowen Basin. Furthermore the empirical CBM IPR correlation for single and multi-phase reservoir was compared. A sorption isotherm was used to limit the maximum recovery and generate recovery efficiency based on the IPR correlation.

One of the potential risks to a CBM development is the likely loss in recovery efficiency due to higher backpressures on wells as a result of suboptimal gathering network sizing due to a chosen surface concept. This risk needed to be further evaluated and addressed for potential outcomes when the field starts production. The study was initiated by means of using the CBM field IPR's to evaluate this risk in more detail, identify mitigation measures and capture any associated opportunities that may be available.
New Solutions for High-Pressure and Salt/Anhydrite Rocks Casing Cementing, A Case Study
Authors: Zhen Nie , He Liu , Zou Jianlong , Xu Daiwen , Zhang Zhenyou , Chen Yufeng
Published: October 2015

High-pressure and salt /anhydrite rocks at 1340-1950m Lower Fars formation present a lot of challenges in 244.5mm casing cementing in Halfaya oilfield due to existing the alternations of salt and anhydrite and clay, high pressure, high salinity(160000~220000ppm), low static temperature (30-70°C) and narrow safety margins (0.08g/cm3), which all contribute to not only limit the achievement of high performance high density salt resistance slurry, but also lead to the low pump rates and bad displacement rates due to the only 0.03 g/cm3 density difference between the drilling fluids with density of 2.25 g/cm3 and the cement slurries with density of 2.28 g/cm3 during cementing operation, and long cementing job duration caused by the constraints of large annular clearance and long isolation interval, so poor slurry performance, severe lost circulation, hole instability and well kick is likely to occur simultaneously during drilling and cementing process, all result in unsuccessful cementing job and poor cement bond quality. In some cases, right after the wells were put on production, the 9 5/8" casing annulus would show an increase in casing head pressure. So a new high efficiency sealing spacer with density of 2.20 g/cm3 was developed to displace drilling fluids effectively, which is composed of weighting agent, suspending agent, dispersing agent, fluid loss agent and anti-leakage agent. At the same time, a new high performance salt resistance slurry system with density of 2.28-2.30g/cm3 has achieved with good stability, proper rheology, and high early strength development of set cement. the 10-15% optimal salt concentration (BWOW) has obtained by the evaluation of rheological property, fluid loss control ability, thickening time property and ultrasonic compressive strength development under the different salt concentration(0~30%); the optimal weighting agent component ratio ((ilmenite: Manganese powder =4:1) and dosage (83%) is determined by building mathematical model to calculate the packing density(φ) of the dry blend with different proportion and water demand, and evaluate slurry properties, introduce a new Carboxylic acid salt salt-resistance dispersant to maintain the good rheological properties. This new slurry technology not only simplify cementing job from the two-stage to one-stage but also improved the cementing bond quality and reduce costs. Extensive lab experiments and pilot tests prior to field application demonstrated the superior performance of this sealing spacer and new salt resistance slurry system; more than 45 wells onsite cementing jobs have been completed in the field with great success. This paper will systematically describe the details of lab development of high density salt resistance slurry system and present case histories to demonstrate its effectiveness in high-pressure and salt /anhydrite rocks casing cementing.
Petroleum Trapping Mechanism Attributed to Facies and Deformation History of Kujung-1 Miocene Carbonate in Ujung Pangkah East Java
Authors: Murtani Anom Seto , Irfree Baharianto , Setyohadi Setyohadi , Dwiperkasa Dhea Wachju
Published: October 2015

Intense compression in northeast Java and facies complexity in carbonates has triggered the complexity of petroleum trapping mechanism. Different fluid contact level between Ujung Pangkah and Sidayu field indicates something has happened during the migration. The shelf edge line that act as the southern trap of Ujung Pangkah that was interpreted in a relatively straight east-west direction can be develop into some other sensible interpretation.

Ujung Pangkah is one of the oil and gas producing fields in the East Java Basin. The field is located in the southwestern part of the JS-1 Ridge. This area is bounded to the east by the Central Deep grabens, Tuban trough the west Kening Deep to the south. The northern margin is east-west highs and lows structure that was formed due to trans-tensional faults initiated by the left lateral strike-slip faulting.

Geochemical analysis shows the hydrocarbon of Ujung Pangkah and Sidayu are from the same kitchen area. Based on the distance and maturity, Kening Trough is believed to be the main hydrocarbon kitchen of the Ujung Pangkah and Sidayu. As the spill point between Sidayu and Ujung Pangkah kept going deeper, this spill point evolved to be a preventer of the hydrocarbon migration to Sidayu while the petroleum kept charging into Ujung Pangkah from the south.

New ways to look at the trap mechanism has lead into some step-out prospects that give advantages to this field to stay productive.
How Powerful Material Balance Analysis Method for Predicting Gas Flooding Performance
Authors: Sutoyo H. R. , Ariadji T. , Aziz P. A. , Mahendra M. L.
Published: October 2015

Gas Flooding is one of the reservoir production management methods which commonly used in the petroleum industry in order to improve oil recoveries and maintaining reservoir pressure. This study discusses two methods in analyzing gas flooding, i.e., material balance analysis and reservoir simulation methods. The objective is to examine the ability and advantages of material balance method with respect to reservoir simulation.

The studied field has three productive zones which consist of two light oil zones and one dry gas zone. Gas flooding scenario was conducted in one light oil reservoir and was modeled using both material balance and reservoir simulation methods to predict reservoir performance for about 14 years and the results were compared to investigate the effect of gas injection. The material balance method employs production, PVT, pressure data, and averaged properties of geological model for a single tank model. On the other hand, the reservoir simulation method uses a compositional model to investigate in detail the effect of injected gas to reservoir fluid behavior and the oil recovery

The examinations indicate that the material balance analysis method shows the advantages of a requiring much less data, but could give reasonably accurate results. Furthermore, the application of material balance analysis in gas flooding could be used for gas injection rate optimization for a very short time manner and could assist for further development of reservoir simulation. For future development, material balance analysis could be used to analyze gas flooding scenario to save time and cost rather than reservoir simulation which takes longer time.
The Production Data Management Platform for Reservoir Management and Optimisation: A Case Study
Authors: Tran T. V. , Hoang H. M. , Tran N. H. , Giang T. H. , Pham K. N.
Published: October 2015

Bien Dong POC (BDPOC) operates two gas condensate fields located offshore Vietnam and exports the produced gas to the Nam Con Son pipeline. Along with the evolution of advanced technology, real time data incorporated into flexible services architecture has contributed significantly in increasing efficiency, accelerating production, reducing downtime and regulatory events (Naser and Awaji 2011). The Production Data Management Platform (PDMS) was implemented before the first commercial gas, allowing the BDPOC to be readily prepared for first gas, enjoy the benefits of tracking all the production and operation parameters since day one for operational purposes and also enable the ability to understand better reservoir dynamics at very early stage of the production (Tran et al. 2014).

With this data converted into information, BDPOC can safely operate the current and future oil and gas assets, accurately report to authorities and stakeholders, perform asset surveillance, diagnosis and ultimately optimize production amid operational constraints.

As the PDMS provides foundation layer for managing the production for the two fields, and it's helping today to improve the timely decision making process through the use of accuracy, and validated data; this effect is impacting positively by allowing BDPOC to adjust production rates to deliver contractual terms of demanded production in a matter of a few hours.

The goal of this paper is to present the architecture and highlight the advantages and benefits that can be drawn from the utilization of the Platform Solution as key foundation block today and how it fits the Roadmap to Asset Optimization in the future for BDPOC.

This case study illustrates the challenges of acquiring, storing, and production information. The main components are deployed for the PDMS along with the up-to-date technologies that can effectively be used to meet these challenges. The Platform Solution allows BDPOC to have reliable production information at their fingertips.
Abnormal Temperature Gradient in North Kuwait; A Case Study
Authors: Millán Arcia Einstein , Cesar Velasquez , Saffar Ali Al
Published: October 2015

A consistent abnormal tendency of the temperature profile has been observed in two neighboring fields belonging to the North Kuwait Asset (NKA), showing lower temperatures in the lowermost structure, and higher temperatures in the uppermost structure within the same Middle Marrat formation. The observed temperature behavior is contrary to what is expected, as uppermost formations typically tend to be cooler than lowermost formations, as dictated by a normal geothermal gradient response.

Formation temperature readings have been crosschecked using 3 independent sources, each showing the same uncharacteristic trend. This phenomenon of temperature gradient inversion has been correlated against fractional fluid composition and geothermal properties of the formation.

Based on available seismic & geological information, there are signs of the existence of overlying "gas clouds", linked to the presence of "Chimneys", which may act as heat source. Massive water bearing shale layers which may act as a natural heat storage chambers have also been detected supporting the presence of abnormal geothermal gradients. The immediate effect of this anomaly has been linked to fluid redistribution. Gravity segregation as the main driver for fluid redistribution has been discarded because the MM formation in one of the fields is highly fractured and its matrix is mostly oil wet, implying a negligible effect of gravity over capillary forces.

The objective of work reported herein is to describe the implications of this abnormal geothermal gradient on fluid thermodynamic gradation and redistribution with depth. Based on actual well test, seismic and geological data, the combined effect of column height and temperature equilibrium on fluid composition was assessed by applying the Equation of State (EOS), while allowing small changes in depth, temperature and pressure gradients.

Discrete fluid composition was determined using available PVT software, and two existing and validated laboratory generated PVT data sets. This in turn was used to reproduce the variation of fluid column with depth that corresponds with the observed abnormal temperature gradient.
Online Bioremediation for Wastesolid and Wastewater at Drilling Waste Management
Authors: Lesto A. , Kusumo P.
Published: October 2015

Hazardous materials that are produced from drilling operation is a sensitive case. It needs more efforts to manage waste material. Online Bioremediation technology is one technology to reduce potential hazardous materials. Bioremediation is eco-friendly technology to remediation hazardous material. It will reduce the hazardous value at waste drilling material through degradation process. Adding Online Bioremediation system will give more protection to environment from potential hazardous materials. Pollutants or contaminants on wastesolid and wastewater are main problems in petroleoum industry. Bioremediation will reduces waste generated during drilling activities to acceptable environmental levels. Usually, Bioremediation process will be treated on land treatment and land farming, and this process will take times and cost. Online Bioremediation technology is in situ bioremediation process. This technology will work in parallel with drilling waste management system. Online Bioremediation will process wastesolid and wastewater in site of drilling projects.
Mechanistic Modeling of Gel Microsphere Surfactant Displacement for Enhanced Oil Recovery after Polymer Flooding
Authors: Chen Xianchao , Feng Qihong , Sepehrnoori Kamy , Goudarzi Ali , Bai Baojun
Published: October 2015

The gel microsphere is an effective profile control agent to mitigate water-channeling problems in mature oil reservoirs. Recently the gel microsphere combined with high effective surfactant is proposed to enhance oil recovery after polymer flooding. Although some experimental and field studies have demonstrated the synergistic effect of polymer/gel microsphere/surfactant, there are no relevant models that can handle the combined effects. Hence, mechanistic modeling is needed for EOR after polymer flooding.

In this work, the transport properties of gel microspheres are combined with polymer and surfactant model. In the coupled model, the migration mechanisms and retention controlling factors of gel microspheres are analyzed according to lab tests, which resulted in the development of the filtration migration equation and dynamic permeability model. The interaction mechanisms between gel microsphere and polymer/surfactant are mathematically described according to experiments, in which the surfactant model is implemented based on a model implemented in a commercial simulator. The coupled model is numerically solved by an implicit-pressure, explicit-compositions (IMPEC) method. The surfactant module is verified with a commercial simulator. The robustness of the coupled model is also validated with a core flooding case to reproduce injection pressure. Furthermore, the coupled model provides an efficient method for predicting gel microsphere-surfactant flooding performance, which helps to determine the technical feasibility of the project.

The interaction between gel microsphere and surfactant is modeled for EOR performance prediction in this work. The newly presented model will help to improve our understanding of the gel microsphere/surfactant flooding.
The Effects of Test Interval on Safety Instrumented Function (SIF) According to Safety Integrity Level (SIL) Value on Three Phase Separator Application
Authors: Biyanto Totok R. , Natawiria Andika D. , Kusuma Franky , Musyafa Ali , Noriyati Ronny D. , Costa Sylvana D. , Irawan Sonny
Published: October 2015

Test interval is an action to verify Safety Integrity Function (SIF) availability. The detection of SIF availability is depends on appropriate test interval value. The test interval value could affect the value of Safety Integrity Level (SIL). This research proposed to demonstrate the effect of the test interval to the obtained value for the specified SIL on SIF. Therefore, SIL value will fit into the architecture of SIF. The case study that used in this paper is three phases separator. The save guards installed in this case are pressure SIF and the relief valve. The result of this research proved that the increasing value of test interval could increase the SIL value. The three phases separator case study with specific hazardous event frequency shown that 0.2 years or 2.4 months is the appropriate value for the test interval.
A Simulating Application of Well Production Allocation to Optimize Wax Formation and Pigging Frequency in Subsea Pipeline for a Gas-Condensate Field
Authors: Tran Nhat C. , Tran Nam H. , Ly Dao V. , Tran Nhut T.
Published: October 2015

Wax deposition is one of the most critical flow assurance issues for the pipeline and regular pigging is a popular method for dealing with them. Predicting and controlling the wax precipitation in the pipeline can help operators to optimize the pigging frequency, this in turn will create significant impact as subsea pigging can be very risky and costly. Yet wax deposition is also difficult to simulate as they are complex mixtures of heavy components from well fluid that freeze out when the temperature is low enough.

In this article, a methodology is developed to optimize pigging frequency. Simulation of wax deposition calculates the precipitation and dissolution due to the variation of fluid flow rate and inlet temperature into the pipeline. The simulation model takes into account all the heat transfer phenomena and hydrocarbon phase behavior along the pipeline. Due to the heat transfer along the production tubing from the reservoir to the well head, the tubing head temperature and respectively the pipeline inlet temperature increase with production flow rate from wells. In other words, the inlet temperature into the pipeline can be adjusted by the wells production allocation. This is one of the key factors that help to optimize the pigging frequency, as a proper wells allocation for a fixed production flow rate can give a high pipeline inlet temperature and flowing temperature, which can help not only to prevent wax formation but also to melt the wax that precipitated earlier.

The methodology is applied to a wax-riched gas condensate field in Vietnam. A proper well allocation plan has been developed, and as a result, the pigging frequency for the infield pipeline for this field can be optimized from conducting monthly to conducting yearly, significantly reducing risks and costs for the operator.
Automated Racking Board Pipe Handling System for Drilling Rigs Ensures Connection Integrity While Providing Safer Working Conditions and Consistent Tripping Speeds With Minimal Rig Modifications
Authors: Vogt Jim
Published: October 2015

Drilling operations, in general, are hazardous in nature and whatever can be done to alleviate this situation is important from a point of view of personnel safety and overall efficiency. Some of the most important drilling operations are pipe handling, tripping, and connection make up. These operations can be inconsistent, causing delays and potentially cause pipe or thread damage to the drill string. Further, these operations are some of the most hazardous on the drilling rig and can be exacerbated by personnel error, fatigue, environmental factors and inclement weather.

To address this, an automated racking board pipe handling system has been developed for land and bottom founded offshore rigs, which has the capability to address the following: Remove personnel from the mast/derrick and the "red zone" areas of the rig floorEliminate swinging pipe, accidental pin/stump contact, and misalignment (which can lead to drill string damage, instability, and added costs)Introduce efficiencies that potentially reduce overall drilling costs by extending pipe life and improving connection operationsControl from an HMI interface in the driller's cabin or via remote control on the rig floorMitigate inefficiencies due to inclement weather and/or environmental factorsEnhance safety in well control situations due to nobody working at elevationEnhance training & communication associated with the derrickman who is no longer working at heightInstallation with minimal modifications to the rig design (racking board modification only)

This paper will describe in detail the features of this automated system, which is compatible with land rigs (double and triple), jack-up, platform, and barge rigs. Additional case studies will show how this step change has been implemented on rigs to date.
Application of Pore Scale Network Modeling Technology for Waterflooding Oil Recovery Evaluation in Different Wettability Conditions
Authors: Zhenpeng Leng , Weifeng Lv , Qingjie Liu , Ninghong Jia , Jianhua Qin , Zhibin Jiang , Danyong Li
Published: October 2015

In oilfield development, waterflooding is normally characterized as an economical and efficient process, which leads to a considerable residual oil saturation. Wettability, being one of fundamental petrophysical properties which reflects interactions between reservoir rock surfaces and fluids during waterflooding, is an essential parameter in reservoir evaluation and simulation, and its effect on waterflooding oil recovery has often been a research hotspot. In this paper, the effect of wettability on waterflooding oil recovery is studied based on a pore scale network model which is a statistical structure of pores and throats extracted from porous media to conduct fluid flow simulation and characterize various physical and chemical effects. A new method combining micro-CT scanning and rate-controlled mercury injection experiment is applied to obtain pore structure data and to improve the representativeness of pore scale network. Multiphase fluid distribution and transportation in pores and throats are simulated by assuming quasi-static flow in pore scale network where both viscous force and capillary force are comparable. A special pore scale network simulation workflow is established, which is capable of simulating two intrusive simulation processes corresponding to oilsaturating with irreducible water and waterflooding, respectively. Wettability is applied in pore scale network model by randomly distributing contact angles onto pores and throats. Based on a series of numerical simulation experiments, it can be summarized that neutral wet condition always corresponds to higher oil recovery than water and oil wet conditions in the waterflooding process, which is consistent with adequate experimental results when preferential wet for one phase fluid is mild. However, simulation results from pore network show that the difference between oil recoveries of water and oil wet conditions doesn't remain constant, which indicates that effect of wettability should be linked with pore structure characteristic when assessing the oil recovery performance. On this basis, characterization of its effect on oil recovery through pore scale network modeling forms an important component of waterflooding development and research for new EOR methods.
Safety Climate Survey among Workers at Oil and Gas Company
Authors: Musa R. Abdullah , Fadli Achmad , Kusminanti Yuni , Erwandi Dadan , Lestari Fatma
Published: October 2015

BOB BSP Pertamina Hulu has been implemented Safety, Health & Enviromental Management System (SHEMS) since its establishment 12 years ago. The study is aimed to obtain the level of SHE perception and becoming values among workers. Survey was measured the safety values in the organization, working unit and individual level as the model of safety climate survey. Data collected through distribute the questionnaires among 436 workers from all levels, top management, middle managers and workers. The average of SHE perception in all workers is 2,28 (scale 1 to 4), as the organizational values is 2,23; as peer group values is 2,4; and as individual values is 2,24. It is indicate that the level of SHE awareness still in moderate level. Safety values that are higher than other safety values are personal appreciation of risk (score 2,57) and commitment management (score 2,53). The lowest safety values are communication (score 1,86) and personal priority and need for safety (score 1,90). Result show that HSE perceptions among employees are still need to be improved. It could be influenced by HSE communication and safety motivation was not effectively being implemented. Company may improve the SHE awareness through strengthening SHEMS implementation, improve the individual skill, safety competencies and two way communications regularly and more intensive.
Application of Thick Salt-Gypsum Formation Cementing Technology in KS Gas Field
Authors: Xueqing Teng , Zhongtao Yuan , Zhengqing Ai , Xiaochun Li , Feng Zhang , Jianguo Zeng , Aiping Liu
Published: October 2015

The most challenging cementing problems that been encountered in KS gas field of Tarim oilfield in China occurred in the salt-gypsum formation having the thickness of about 1000~3000m and the maximum depth of 7000m above. In most cases, there are high pressure saltwater layers among the salt-gypsum formation with the highest pressure gradient of 2.60g/cm3.

HPHT (130 MPa, 160 °C, BHST), ultra deep well and narrow safety density window with the density of about 0.07-0.12 g/cm3 brought huge problems which made the well cementing very hard to achieve good bonding quality, especially for production liner cementing. The qualification rate of cementing quality of the salt-gypsum formation section was only about 40% in 2013. The bad cement bonding quality was recognized as one of the main reasons for this issue, which was the one of the top headaches for the operator.

To answer these challenges, the ultra-high strength toughness casing, casing running downhole simulating technology, salt-tolerant spacer fluid and high density cement slurry, and step by step pressurized casing annular cement until cement set have been developed and applied successfully. The qualification rate of cementing quality of the salt-gypsum Layer section increased to 78% in 2014.

The successful application of these techniques improving cementing quality of the significant thick salt-gypsum formation under the extremely challenging downhole condition promoted the exploration and development of ultra-deep subsalt reservoirs in China.
An Attempt to Revitalize Watered-Out Gas Condensate Fractured Reservoir by Gas Injection
Authors: Adachi Y. , Hasegawa T. , Yamamoto H. , Hosokoshi K. , Anraku T.
Published: October 2015

This work challenges to the redevelopment of a mature gas condensate fractured reservoir with strong aquifer. Typically, fractured basement reservoirs have the inherent disadvantages; rapid decline rate, limited reserves, early water coning, and so on. Flow simulation model is built by an actual field data to evaluate lean gas injection even in watered-out gas condensate reservoirs. We verified the potentiality of gas injection method as EOR/EGR techniques in simulation case studies. The result of simulation study indicates that considerable amount of condensate can be recovered and the native gas can be recovered durng gas injection and reproduction.
The Relative Attractiveness of US LNG Exports - Is the Threat to Australian Projects Real?
Authors: Chandra V.
Published: October 2015

The competitiveness of Australian LNG projects versus US projects has been a subject of much debate. However, as oil prices have fallen since mid-2014, the debate has shifted from the relative pricing terms of the LNG sales contracts to the relative cost of supply. Falling oil prices has decreased the price of LNG in traditional oil-linked price markets of Asia. Lower cost of LNG will increase the demand for gas, especially in the power generation sector. New gas supply will be required to meet increased demand – but the new supply must be at a competitive cost. The market price will be set by the marginal cost of incremental supply. Legacy projects in SE Asia, Middle East and Australia are unable to increase their volumes. The only other source of incremental supply that can profitably sell at these lower prices are new projects in the US Gulf Coast. Australian greenfield projects will not be able to sell at these prices. Australian greenfield projects suffer from high capex, high feed gas prices, and high operating costs. By contrast, US Gulf Coast LNG projects are being constructed as significantly lower unit costs, have access to massive low-cost shale gas volumes, and will operate at low costs using standard technology. These projects are ideally placed to operate in the lower priced environment, irrespective of the pricing index of the LNG sales contracts.
Transportation of Metal Oxide Nanoparticles Through Various Porous Media for Enhanced Oil Recovery
Authors: Bayat Ali Esfandyari , Junin Radzuan
Published: October 2015

Recently, considerable attention has been focused on the application of nanoparticles (NPs) for enhanced oil recovery (EOR) purposes. Previous studies on NPs transportation in porous media were conducted in subsurface alluvial zones and sandy soils which did not cover the whole conditions in oil fields. Besides, issues of how and where these materials distribute into the porous media remain major challenges. In this study, mechanisms governing the transport and retention of three metal oxide nanoparticles (NPs) namely Al2O3, TiO2, and SiO2 through limestone and quartz sand porous media were firstly investigated. Then, the named NPs were applied for enhanced oil recovery purpose in these porous media. For this aim, the nanopowders were dispersed in de-ionized water at concentration of 0.005wt%. Vertical columns were packed using limestone, and quartz sand grains in the range of 125 to 175µm. Breakthrough curves in the columns effluents were measured by UV-VIS spectrometry. It was found that the mobility of named NPs through mentioned porous media strongly depends on the NPs surface charge and stability as well as porous media surface charge and roughness. The obtained results from transport experimental tests were found to be in agreement with the classical filtration and Derjaguin-Landau-Verwey-Overbeek (DLVO) theories. Moreover, amount of oil recovery by the NPs was found to have direct relationship with their mobility through porous media where NPs with higher mobilities cause higher oil recoveries.
Successful Co-Development of Oil and Gas Reservoirs, A Case Study
Authors: Xueqing Tang , Ruifeng Wang , Xiunian Liu
Published: October 2015

Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The total number of drilled was 19, including 5 updip wells penetrated oil and gas zones, the remaining 14 downdip wells completed at principal oil zones. A unique co-development project of oil and gas had been performed since the start-up of field in July, 2010, including three phases:

Phase I: Prior to start-up of the field, In-situ gas injection was initiated. Single tubing string completion was utilized in updip wells, packer isolated oil and gas zones so that high-pressure gas could produce from the tubing and oil could produce from the annulus. After commencement, gas from updip wells was injected into downdip wells to maintain reservoir pressure and minimize water influx. The remaining gas was used to gas-lift at updip wells.

Phase II: Following pressure depletion of oil and condensate gas zones, gas-lift wells became inefficient. The packerless tubing string was extended to the bottom of perforations for commingling production of oil and gas condensate zones at updip wells. Well stream was produced from the casing annulus while recycling gas was injectied from compressors into the tubing for gas lift. Nitrogen injection was conducted at downdip wells.

Phase III: After water breakthrough, infill wells between updip and downdip wells were drilled for nitrogen injection to mitigate the water cut rising trend.

Actual production performance of oil and gas co-development is better than sequential production of oil and gas. Initial well production at two producers reached over 10,000 BOPD, Current recovery factor for oil is 25% and gas is 36%. Oil is producing at the level of 18,000 BOPD with average offtake rate of 5.8%. Simulation confirmed that ultimate recovery factor for oil could be over 50%.