bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Analysis of Discontinuities in Single Phase Flow - Vibration and Pressure Fluctuation Measurements
Authors: Karim Hafiz , Ancian Loïc
Published: October 2017

Current know-how in the field of piping system analysis remains incomplete with room for progress. Indeed, piping vibration can come from several sources: direct or indirect machine excitations, cavitation and acoustic excitation due to differential pressure devices or excitations due to fluid flow. This last topic has long been identified as essential and the Energy Institute (EI) Guidelines for the Avoidance of Fatigue Failure that are more and more often applied in both design and operation confirm the importance of this subject.

The use of such guidelines presents certain technical shortcomings: to date, there is limited information available for predicting vibration levels caused by turbulent flow. If piping responses are known, their excitation sources remain unknown, leading to suggesting solutions that tend to be more complex, potentially over-dimensioned and less cost-efficient than truly required.

The aim of this paper is to present FIV sources for several discontinuities that are present in piping systems.

In order to better understand the parameters that govern turbulent excitations, a series of measurements (pressure and vibration) was performed in the vicinity of several singularities.

Three common potential irregularities usually met in pipelines were selected for the study. Only restricted orifices (RO) are presented in this paper.

Two different test loops which have different characteristics in terms of size and flow were used for the measurements, making it possible to validate dimensionless analyses in order to compare results obtained from both loops.

The characteristics of the two loops place the acoustic modes of their systems in the frequency range of interest. Considering that the turbulent phenomenon is coherent on small distances whereas acoustic plane waves are coherent over long distances, coherence was used to separate the acoustic part from the total measured signals.

A dimensionless analysis was then performed, enabling the comparison of measurements from both test loops, determining if specific behavior was associated with an acoustic or a turbulent phenomenon and validating the hypotheses such as the homogeneity of the turbulent flow.

These results on a straight pipe (similar for different rates and pipe sizes) demonstrate the consistence of the dimensionless analysis and were used as a reference pressure level for further comparisons with levels obtained in the presence of a singularity.

The evolution of pressure fluctuations in function of the distance was extracted in this new configuration. Location and amplitude of these fluctuations were compared for different sizes.

The measurements and techniques used during this study make it possible to predict the amplitude and location of maximum of pressure fluctuations downstream of most common piping discontinuities such as restricted orifices.
Review of Coal Bed Methane Prospect in Indonesia
Authors: Irawan C. , Nurcahyanto D. , Azmy I. F , Paju J. A. , Ernata W. M.
Published: October 2017

Indonesia has began the unconventional operation since 2003, VICO and MEDCO as a pioneer in Coal Bed Methane (CBM) working Area. Since 2005, two (2) big company has begun study and survey seismic operation for Kutai Basin (VICO Indonesia) and South Sumatera Basin (MEDCO E&P). The results are neededmore survey seismic and massive drilling well, which the needs of study and evaluation to get more comprehensive calculation on gas methane reserves and the strategy of Exploration and Development phase on each basin

The success ratio by numbers of drilling operation of CBM wells in Kutai Basin and Sumatera Basin were not significantly good as early prediction. This condition made some CBM contractors working areas has to leave and do farm out from the area. Nowadays, by counting the total of Unconventional Working Area in Indonesia, the active operation area are around 40 places in Sumatera and Kalimantan.

The slow down activities of CBM operation are caused by the minimum number of success ratio to discovery and to produce Methane Gas; challenge for the contractors to fullfill the commitment which where list stated on Production Sharing Contract (PSC). Other obstacles are the permits, where contractors get more difficulties to do all the activities, such as land acquisition permit (IPPKH if needed), environment permit (UKL/UPL), Rig License permit, procurement process and else.

Nowadays, Government of Indonesia has given more simplication for contractors in Regulatory area, Procurement Policy and Operating Procedure Guideline to do CBM activitiesin Indonesia.

With several breakthroughs have been taken by the Government of Indonesia, in future prospect CBM activities will be expected back to normal with more efficient by collaboration of government and contractor for technical and technology in exploration and drilling activities. By the results of Methane Gas discovery increased the Total Reserves and Energy Resilience of Gas in Indonesia.
Investigation and Application of Reciprocating Direct-Drive Electric Submersible Plunger Pump Lifting Technology
Authors: Guoxing Zheng , Weishan Du , Qi Wang , Lin Wang , Fengshan Wang , Yanan Sun , Guoqing Wang , Weike Wang , Yang Gao
Published: October 2017

Aiming at the poor applicability, high unproductive energy consumption and the serious wear of the sucker and tube during the application of oil pumping units, screw pumps and electric submersible pumps in low-production and low-permeability wells, directional wells and exceptional wells, a new reciprocating direct-drive electric submersible plunger pump has been developed.

For reciprocating direct-drive electric submersible plunger-pump lifting technology, the rotor of submersible linear motor is connected with the plunger of oil-well pump; cable is applied to supply electric energy for the downhole submersible linear motor; and the rotor of motor directly drives the plunger pump to reciprocate and finally realizes the lifting of the produced liquid.

For this new-type lifting technology, downhole direct-drive rodless lifting mode is applied, which successfully prevents the wear of the sucker and tube and avoids the unproductive energy consumption that is caused by the movement of sucker rod string when oil pumping units, screw pumps and other rod lifting methods are adopted. Compared to the oil pumping unit with the same displacement, the application of the reciprocating direct-drive electric submersible plunger pump can reduce electric power consumption by more than 40%. Moreover, this new-style reciprocating direct-drive electric submersible plunger pump has no surface movable component, and the well head is sealed. Therefore, it is safe, environmental friendly and easy to maintain.
Numerical Simulation Method and Laboratory Experiments of Starting Pressure Gradient in Tight Sandstone Oil Reservoirs
Authors: Wang Shuai , Tan Xianhong , Zhang Shaohui , Jiang Haimei , Jiang Donglei , Ruan Hongjiang , Zhang Xiaoxia
Published: October 2017

In the process of the tight oilfields development, it is difficult to establish an effective system of injection-production displacement because of the high seepage resistance. The seepage does not follow the linear Darcy's law. However, the reservoir simulation software has not considered this phenomenon, which leads to the numerical simulation prediction results better than actual production data. Therefore, it is necessary to establish an effective method to calculate the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation.

This paper introduced a factor called starting pressure gradient (SPG), which can be used to describe non-Darcy seepage phenomenon. First of all, laboratory experiments of differential pressure flow method were carried out to get the relationship between core permeability and the SPG. In addition, according to the reservoir heterogeneity and exploitation degree, three methods were put forward for characterization the SPG in tight sandstone oil reservoirs numerical simulation. Finally, this numerical simulation method was used in the X tight sandstone oil reservoir history matching process to verify its accuracy.

The results of the laboratory experiments showed that, SPG exists in tight sandstone oil reservoirs. Liquid starts to flow when the production pressure gradient is greater than the SPG. SPG is an additional pressure resistance for each flow unit, the existence of SPG has intensified the degree of pressure drop. Analysis of the experimental data gave a power series relationship between the SPG and the permeability. And the SPG increases with the decreases of core permeability.

Reservoir heterogeneity criterion was established by introducing R and C factors. The greater R value and C values are, the higher the heterogeneity is. When the reservoir heterogeneity is weak (0< R≤0.3), we set SPG for each layer. When the reservoir heterogeneity is strong (0.3 < R≤ 1 or 0 < C≤1), we set SPG for each rock type. When the reservoir with intense heterogeneity (1<C<2), we set SPG for each gird.

After considering SPG, single well history matching coincidence rate improves from 64% to 87%, and every layer oil production prediction has high coincidence with the actual production data. Therefore, SPG cannot be ignored in tight sandstone oil reservoirs numerical simulation.

This paper provides a new method to describe the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation, and can guide the tight sandstone oil reservoirs development effectively. This method can also be applied in heavy oil reservoirs and tight gas reservoirs numerical simulation.
Fit-for-Purpose Chemical EOR ASP Modeling Strategy to Guide Pilot Development Decisions for a Giant Reservoir in North Kuwait
Authors: Al-Dhuwaihi A. S. , AlAbdullah M. B. , Tiwari S. , Al-Murayri M. T. , Al-Mayyan H. , Shahin G. T. , Shukla S.
Published: October 2017

This paper focuses on a chemical EOR feasibility study for Raudhatain Zubair (RAZU) reservoir in North Kuwait. The study describes a methodical approach to enable pilot location selection, and a fit-for-purpose modeling strategy to guide the Alkaline Surfactant Polymer (ASP) pilot design decisions. The objective of the pilot is to test in the field that ASP chemicals could mobilize remaining oil and drive it to the producers, where it is captured, produced and separated at the surface.

A detailed study was conducted that focused first on mapping out the distribution of remaining oil in the Raudhatain Zubair (RAZU) sandstone reservoir, defining the subsurface uncertainties and identifying key decisions that needed to be addressed for the pilot design. Thereafter, a fit-for-purpose probabilistic dynamic model using a range of inputs based on available rock and fluid field data and ASP parameters from an in-house global Chemical EOR database was built. This model was used to predict the range of production outcomes and aid with pilot design decisions.

Based on the stated objective of the pilot, an inverted 5-spot pilot pattern was chosen and a representative area was identified that spanned a reasonable average of field properties. An uncertainty analysis on the pilot pattern revealed that the residual oil saturation to both water and chemical and the remaining oil saturation at the commencement of pilot are the largest uncertainties governing the incremental oil recovery from ASP over water flood. Another significant uncertainty was the presence of an aquifer and the influence of active injectors near the pilot area. Depending on the aquifer strength and heterogeneity of the reservoir, fluid drift and can sweep the chemical slug away from the intended target region of the 5 spot pattern. On the design side, the chosen surfactant concentration in ASP slug, which affects the residual oil saturation to chemical, can result in lower than optimal oil recovery if surfactant losses (via adsorption or chemical consumption) are not adequately managed. Other important decisions are injection rate and pattern size since they affect the incremental recovery due to different swept pore volumes in the pilot pattern. Moreover, the model helped in steering important decisions for the pilot – e.g optimum time to switch to ASP injection after water flood.

ASP sector models frequently suffer from being overly complex since they are not tailored to address practical questions that drive key pilot decisions in a timely manner. The unique practical modeling approach presented here focuses on identifying critical uncertainties and pilot design parameters while circumventing the need of detailed laboratory data and a full field model history match.
Improving Parameter Uncertainty Constraints for Coal Seam Gas Reservoir Simulation using Single Well Models with Particular Emphasis on Relative Permeabilty Assumptions
Authors: Furniss J. P. , Hodgkinson J. , Bottomley W. , Luo Y.
Published: October 2017

This paper presents elements of an extensive single well modelling (SWM) programme to improve confidence in the parameters used to condition the full-field reservoir simulation model. The impacts of local grid refinement (LGR), fine vs upscaled layering, and a range of static and dynamic properties have been investigated.

Values for some fundamental input parameters for coal seam gas (CSG) reservoir simulation, such as coal fracture porosity and relative permeability, are extremely difficult to constrain by laboratory test results and are typically derived from history matching studies. Also, the stress and shrinkage dependent permeability effects exhibited by many coal cleat systems can be very difficult to characterise and other parameter variations could be invoked to produce similar trends in simulated water and gas production and flowing bottom-hole pressure (FBHP) behaviour. Many of QGC's CSG well production histories exhibit some very large pressure drawdowns, and obtaining a good history match to water and gas production histories in addition to shut-in bottom hole pressure (SIBHP) and flowing bottom hole pressure can be problematic for many of these wells. Simulation input parameters such as permeability, porosity and cell to cell transmissibility have been investigated using a wide range of values. Up to now, it has generally been possible to match water and gas rates and either SIBHP or FBHP, but not both pressures.

Relative permeability and coal gas saturation have been the most effective parameters used to obtain an acceptable history match (HM) in recent modelling efforts. The full-field modelling assumptions for these parameters have now been validated and informed by the SWM work reported in this paper, and the range of uncertainty narrowed for these critical parameters. For the wells exhibiting the highest drawdowns, initially a very good match was obtained using a very ‘aggressive’ suite of relative permeability parameters and an irreducible water saturation of around 90%. This relies on an assumption of very low or zero critical gas saturation and extremely rapid reductions in water relative permeability as gas begins to desorb from the coal matrix and enter the coal fractures. The validity of these assumptions has been tested by considering wellbore modelling effects, to reducethe reliance on aggressive relative permeability parameters to achieve a history match. The full-field model (FFM) gridding assumptions have also been validated by this work.
Research of Floor Horizontal Well Staged Fracturing Technology
Authors: Cao L. , Yang X. , Zhang S. , Wang H. , Wang K. , Liu J. , Zhao J.
Published: October 2017

Since the coal seam is soft with low permeability in China, the stimulation effect of vertical well hydraulic fracturing technology is limited while horizontal well fracturing has instable wellbore leading to wellbore collapsing. Therefore, floor horizontal well hydraulic fracturing technology is proposed, that is drilling in the floor sandstone and connecting the coal seam by hydraulic fractures. A test area has been undertaken in 3# coal seam, southern Qinshui Basin, to demonstrate this technology. Through optimizing the well path, borehole structure, fracturing designs, and fracture propagation performance, a set of treatments were developed and applied successfully. The result shows that drilling floor horizontal well along with minimum horizontal principle stress, applying U-type well structure, and designing fractures with 3 stages, 130m half fracture length and 30D·cm flow conductivity achieves better production performance.
Integrated Waterflood Connectivity Analysis in Compartmentalised Reservoir of Windri Area, Asri Basin, Indonesia
Authors: Widiatmo R. , Gunawan H. , Afi F. N. , Waskito L. B. , Nugroho P. , Sunarta J.
Published: October 2017

This paper describes an efficient approach to evaluate waterflood connectivity performance in complex compartmentalized reservoir, the objectives are to increase the oil production performance and manage mature fields effectively, and also to enhance ultimate recovery in the long run. It is also very useful to get better understanding of detail reservoir characterization, reservoir internal architecture, reservoir distribution, pressure monitoring and subsequent water flood sweep pattern efficiency. Multi-disciplinary methods applied to maximizing all of data and create strong analysis. The first phase is deep sub-surface analysis in property distribution, simultaneous inversion, 4D time lapse seismic and sweep pattern analysis, those analysis have been done to get comprehensive interpretation of reservoir characterization and waterflood monitoring. The second phase is tracer injection, we implement tracer in several wells to ensure connectivity from injector to several producers are efficient and optimal. These methods were performed for several regions of this area which contains a large number of well, nearly 200 wells consist of vertical, deviated and horizontal wells. Reservoir distribution in Windri area interpreted as stacking channel with high sinuosity geometry. This reservoir consists of predominantly of marginal marine claystone interbedded with deltaic sandstones, thin limestone and coal. Bio-stratigraphic analysis from cores shows that the reservoir was deposited in estuarine setting, interrupted by a brief shallow marine incursion. Seismic amplitude mapping at the upper base Gita horizon reveals a system of meandering channels. Compartmentalised reservoir in Windri area divided into 5 sweep pattern to make analysis more detail and accurate. Each of compartment have different characteristic, this is the challenging part in Windri area. East of windri area channel divided into 4 channels and it shows the evolution and movement of the channel that can control the property distribution and reservoir connectivity. Group two shows good result from tracer injection and it is supporting the interpretation of reservoir distribution and characterization within the area. Integrated 4D time lapse seismic generate pressure monitoring movement from each of waterflood phase. The results of this integrated study implementation are excellent, the ineffective water injection pattern now become effective, there is no unavailing injection well, every pattern is connected and link to each other, so that we can achieve our goal to enhanced recovery factor from 16% to 20%. Reservoir characterization using multi-discipline method reduce uncertainty of heteroginity sand and fluid prediction. Integrated waterflood analysis has been implemented for prospect generation, production optimization and overcome pressure degredation in this area.
Triggering Cavitation in Multilateral Coiled Tubing Drilling by High Pressure Water Jet
Authors: Peng Kewen , Li Gensheng , Tian Shouceng , Huang Zhongwei , Zhang Zhenxiang , Zhu Bin , Nie Xiaokang
Published: October 2017

Recently high pressure water jet drilling is proposed for coalbed methane development by connecting nozzle with coiled tubing directly. However, rock breaking efficiency is still compromised because of the hydraulic energy loss when water flows through the small size coiled tubing. Cavitation is the formation of vapor in a liquid when the local pressure in the fluid is reduced to its saturated vapor pressure. The violent bubble collapse can cause severe damage to the materials caused by the high collapse pressure and temperature.

In this paper, based on bottomhole flow field analysis and nozzle survey, a convergent-divergent nozzle is optimized to trigger cavitation in water jet for multilateral drilling. A mathematical model coupling the flow field and bubble dynamics is used to predict the effective standoff distance for cavitation erosion. The classic Rayleigh-Plesset equation is solved by first order Euler finite difference at each step with a thermodynamic model. Then, laboratory experiments are conducted in a pressure vessel to validate the calculation results based on pitting analysis.

The results show that the divergent section of the nozzle is critical to generate low pressure regions inside the throat section, but not hindering bubble transportation towards the specimen outside. The optimized divergent angle is 20° and divergent length is 4 times nozzle diameter. In addition, it is demonstrated that the cavitation bubbles formed inside the nozzle can be transported to the outside flowfield against adverse pressure gradient due to its inertia. The effects of flow rate and ambient pressure on the effective standoff distance are investigated. Given certain ambient pressure, there exists a threshhold of flow rate, below which cavitation bubble can't be transported outside the nozzle. The experiment shows the maginitude of the cavitation impacts lies in the range of 800 MPa to 2700 MPa.

The present research, to our best knowledge, is the first systematic investigation on utilizing cavitation to increase erosion rate in multilateral CTD drilling. The nozzle proposed has a good compatibility with the coiled tubing. The proposed mathematical model can be used to assist engineering design and operational parameters adjustment.
Comprehensive Sanding Study from Laboratory Experiments, Modeling, Field Implementation, to Real-Time Monitoring, a Case Study for Hai Thach and Moc Tinh Fields, Offshore Vietnam
Authors: Hoang Son K. , Trinh Vinh X. , Tran Tung V. , Dang Tuan A.
Published: October 2017

This case study reports a comprehensive sanding study program for two offshore gas-condensate fields. The results from geomechanics laboratory testing and modeling of sand production were implemented into real-time monitoring of production wells using the Production Data Management System (PDMS). Sand detectors were also instrumented on all production wellheads and integrated into the real-time monitoring. The program will help define the envelopes of optimized production while ensuring safety of production facilities.

Comprehensive geomechanics laboratory testing was conducted on reservoir cores retrieved from exploration and production wells. In addition to unconfined compression tests and TWC tests, the testing included triaxial tests with acoustic velocities during hydrostatic confinement as well as deviatoric axial loading to determine formation rock strength and deformation behaviors. The laboratory results were then used to calibrate strength and elastic properties logs used in sand production modeling. Optimized production envelopes for each well could then be determined. Finally, the modeling results were integrated into PDMS so that downhole gauge pressure and sand detector readings could be monitored and managed real-time for all production wells.

The results revealed that many reservoirs in Hai Thach and Moc Tinh fields have relatively low strength and therefore moderate sanding potential. This study would help define the envelopes of optimized production while ensuring safety of production facilities. These envelopes included sanding prevention criteria in addition to criteria to optimize condensate production and minimize water production. Regarding sand production, downhole gauge pressure are monitored real-time and managed so that drawdowns are below sand production threshold at current reservoir pressures. The key functionality goal is real-time collaboration between onshore and offshore to establish reliable information for reservoir monitoring, improving modeling, and production losses mitigation, which significantly improves production through a proactive well management.
A New Concept of Sand Management Philosophy; Revolutionary & Cost Effective Solution
Authors: Hamza N. , Baghdadi F. , Yahia Z. , Madon B.
Published: October 2017

In the current oil price environment, all new developments are pursued with minimum capital investment and lowest possible operating cost to improve project economics. Projects that do not meet the economic criteria have to be shelved or deferred to a later date. This was the case for a green gas field development in Peninsular Malaysia which was shelved in 2016, resulting in an added preservation requirement for the newly-fabricated topside facilities and pipelines. The increase in project cost due to the preservation requirements, eroded the project economics which necessitates all possible cost reductions in order to make the overall project economically viable.

One possible area for cost reduction is the sand management. Sand production is expected from the shallower I-group reservoirs targeted in the gas development. This is based on well test results conducted in one of the appraisal wells which is further supported by a sand production prediction (SPP) study. Based on the available Particle Size Distribution (PSD) data from a Laser Particle Sieve Analysis (LPSA), the reservoir particle D50 is about 55µm and has more than 40% fines content. Due to the multilayer reservoir targets, cased hole development were designed for the well hence Internal Gravel pack (IGP) is selected as the downhole sand exclusion method.

Over the life of the field, fines production is anticipated due to the high fines content of the reservoir. There is also risk of IGP failure which could result in eroded tubings, flowlines and headers. This would be catasthropic for the green field due to its unmanned operation philosophy. Moreover, during the facilities detailed design, the provision for surface desander was eliminated to make way for a compact platform design.

This paper will describe the methodology used to assess the severity of sand production to the surface facilities using the well and reservoir parameters. The assessment results provide the basis for the field integrated sand management philosophy, which helps management to make an informed decision to eliminate the real time sand monitoring and control system requirements and also eliminate the need for platform deck extension for desander installation requirement.
Investigation of Failed LNG Boil Off Gas Transfer Line Expansion Bellows Using Finite Element Analysis Approach
Authors: Pratama E. Y.
Published: October 2017

Badak LNG operates two loading docks for loading LNG to transporting vessels. Each loading dock is served by two main piping systems. One piping system used to transfer the LNG from the storage tanks to the loading arms and another piping system to transfer the boil off gas (BOG) from the vessels back to the plant, to be utilized as fuel. Both piping systems are equipped with expansion bellows installed to compensate piping contraction and expansion cycles, caused by temperature cycle during operation. Several gas leaking events have occurred on expansion bellows of BOG piping, resulting in dock unavailability and may result in interruption of LNG shipping schedule. Preliminary specification review suggested that the subjected bellows operational cycles were far below the designed number of cycle. This fact, along with the evidence of bulging sections found at five to seven o'clock position, indicated possible overstress phenomenon. This study verifies the overstress phenomenon and recommends the counter measures to prevent similar problem by implementing three approaches i.e.: reviewing the bellows design and specification, developing piping stress model to obtain general overview of stress experienced by piping system in comparison to the result against the construction code, and developing finite element model to obtain more detailed stress profile within the bellows convolutions. The study results showed that the main cause of the overstress condition is a steep temperature gradient between the bottom and the top side of the bellows during transient period of cooling process of BOG piping, which happened in every loading schedule. To prevent similar failure, a change in bellows specification, modification of piping supports and installation of temperature transmitter to enable monitoring and control of BOG cooling process are recommended to be implemented.
Design and Application Evaluation of Vacuum Insulated Tubing for Wax Control in Bohai Oilfield
Authors: Liu Yigang , Shang Baobing , Wu Huaxiao , Bai Jianhua , Meng Xianghai , Ma Jun , Mu Mei , Jiang Zhaobiao
Published: October 2017

Bohai J Oilfield has typical characteristics of high wax content and wax precipitation point (WPT). Wax deposition in the tubing had been an ongoing problem after this Oilfield came on stream, which caused significant productivity losses. Various methods of wax control and removal, such as injection of wax inhibitor, wireline dewaxing, hot-water treatment and continuous tubing had been tried to guarantee the normal production of the wells. However, none of these methods was long-time effective. Considering that vacuum-insulated tubing (VIT) plays an important role in thermal insulation, 4 wells of J Oilfield are equipped with different length of VIT for wax control by increasing the flowing wellhead temperature (FWHT).

This paper presents the methodology for design of VIT as well as the application evaluation in the 4 wells. The apparent heat transfer coefficient of VIT is determined after analyzing the influence of coupling on VIT heat transfer properties. The distribution of wellbore temperature profile is calculated based on conservation of energy. Existing FWHT data is collected to verify the accuracy of the temperature profile calculation model. As a result, the length of VIT installed for each well is optimized through sensitivity analysis. After VIT is installed, the production performance of the 4 target wells is monitored.

After installing VIT, FWHT of the 4 wells obviously increased, and no wax deposition occurred any more when the production was stable. The actual FWHT agrees well with the prediction result, indicating the accuracy of numerical calculation.

The successful application of VIT for wax control for the first time in Bohai Oilfield indicates its effectiveness for Chinese offshore wells. This will also be one promising wax control method for other similar wells.
Maintaining Operation Excellence in Simultaneous Operation at Offshore and Delta Area
Authors: Marzuki I. , Junaedy H.
Published: October 2017

Robust co-activities management is one key to combine continuous production and development in upstream operation. In the context of Mahakam Block, green and brown field developments are continuously adding portfolio, simultaneously with routine production activities. Huge volume of simultaneous operation in Mahakam could be seen in 2013 operation, with more than 20 million manhours, 6 Jack up Rigs, 5 Swamp Barge Rigs, 36 Well Intervention barges, 22 Construction Barges were managed. This paper will describe specifity of simultaneous operation in Mahakam Block, and presenting improvement efforts to maintain operation excellence of simultaneous activities in offshore and swamp in the past 3 years.

Simultaneous operations in Mahakam are applicable in the field of production with drilling, well intervention, and construction / project. The improvement efforts went through mapping, gap analysis, workshop, and validation. Organization improvement efforts were including standard guideline to determine work criticality using quantitative approach, introduction of routine coactivity matrix and recurrent activities sheets. The guideline has successfully helping harmonization among operation sites and all stakeholders. Reinforcement of audit is another aspect contributing to overall excellence of TEPI safety and production performance in 2016.
New Considerations of Shale Gas CO2-EGR from Molecular Simulation
Authors: Xiaoqi Wang , Xu Jin , Jianming Li , Liang Sun , Xiaodan Liu , Zengqiang Zhai
Published: October 2017

Following North America, shale gas has been proved to be a success in China, considering the commercial exploitation of shale gas in Sichuan province in China, and a continuous increase in the past few years and a good momentum in the next few years. This mainly attributes to the horizontal drilling and multistage hydraulic fracturing technologies and huge capital investment. However, we need to face that even using these advanced technologies, a sharp decrease of the production during the development still exists in all shale gas wells, due to the tightness of the shale matrix and the pressure drop in the fracture network.

According to the successful experience of enhanced coalbed methane recovery all over the world, CO2 injection shows a promising future in EGR (enhanced gas recovery) process for shale reservoirs. In the meanwhile, CO2 can be simultaneously sealed underground to reduce pollution. Therefore, in order to guide the engineering process, it is of great importance to reveal the CO2 and CH4 absorption behaviors at microscopic scale,but the corresponding mechanism is as yet unclear. This is because the competitive adsorption process of CO2 and CH4 underground can be affected by a lot of parameters, such as pore size, temperature, pressure, CO2 concentration, etc., and laboratory experiment is usually difficult to carry out, due to limited laboratory temperature and pressure conditions, and difficulty in separating porous OM from shale, etc.

In this paper, we employ molecular simulation of CO2-CH4 competitive adsorption behavior in organic matter (OM) nano pores. Using Longmaxi shale as sample, OM pore structure was first characterized using FIB-SEM and scanning ion microscope, and pore-size distribution was studied using N2 adsorption. Then a simplified pillar-layer model was used to study CH4 adsorption behavior and competitive adsorption effect between CO2 and CH4, using grand canonical Monte Carlo (GCMC) method. Results indicate that nanopores with good connectivity widely exist in OM, offering important storage space for absorbed shale gas. The amount of adsorbed CH4 can increase with lower temperature and increased pressure, and overpressure will significantly increase the amount of CH4 adsorbed underground; CO2 shows high competitive adsorption ability; CO2/CH4 selectivity coefficient decreases dramatically with increasing temperature or pressure, or both, and it corresponds to deeper burial depth. CO2 EGR during shale gas exploration will be more efficient, if it is conducted after the pressure drops to a certain degree.
Unlocking Common Approach of Well Control Equipment for Mechanical Well Service
Authors: Suprihono Sanny
Published: October 2017

The challenge to maintain production in marginal field and to keep any related activities to be economically justified will require more optimization and innovation. Artificial lift fields using pump require many mechanical well service intervention: to install and to repair the downhole pump. Mechanical well service uses well service rig or pulling unit rig, mainly to pull and to run the tubing. One of main component of the rig is well control equipment system.

The complete package of the well control equipment system is about 30% of the rig service package. The equipment may consist of: complete BOP stack, hydraulic power unit with line, choke manifold, kill line and flare line, poor boy separator. The time needed to rig up, test, and rig down the well control equipment package has significant percentage. For simple job of artificial lift mechanical well service which main job is only pulling and running back the tubing, the percentage may be about 20% - 30%. Continuous and routine job of the mechanical well service will give significant cost impact to the total operation expenses.

One of the marginal on shore fields in Tunisia, with low productive oil production well, requires innovation to keep the production in economic limit. Cost reduction of the artificial lift well service operation is one of the main options. Optimization of the well control equipment was studied to reduce the field operation cost. Careful risk assessment had been done. Simple and low cost well control equipment was prepared. Additional procedure was introducedandsome documents related to risk control are prepared. Applying the approach, about 25% - 30% of cost saving is identified without sacrify the safety of the operation.

Well control equipment standard is an almost matured and well-regulated standard around the world. The main equipment standards are almost the same across regions, countries and companies. Mostly there are two categories of the standards related to well operation: drilling and well service. However, mostly the main well control equipment is the same for both drilling and well service. Off shore well control standard are more stringent than on shore operation. However, mechanical well service,which deals with existing perforation without any reservoir stimulation and very well-known production behaviors, are not specifically categorized in most of the standards. This type of on shore mechanical well service operation has much less risk than drilling or reservoir well service, so it is highly possible to use less well control equipment package with the proper risk assessment according to the field/well condition. The well control equipment applied in the Tunisia field will hopefully give more standard guidance for low risk marginal oil field.
Application of Allocation Algorithm for Surveillance and Optimization of Intelligent Wells
Authors: Chuen C. Mabel , Nukman M. Agus , Mandal Dipak , Salim A. S. , Sepulveda W. , Vaca J. C. , Goh K.
Published: October 2017

Overproduction of water is an inevitable risk in most mature oil fields. Operators have a high expenditure in both OPEX and CAPEX to delay the influx of water production, which is reducing both field life and economic value. With the advent of reservoir control technologies, oil production wells are now fitted with downhole pressure and temperature gauges and downhole flow control valves (FCV). These ‘intelligent’ wells provide valuable data for reservoir surveillance, and operators can control drawdown pressure to reduce water influx from high water production reservoirs. However, further analysis is required to identify zonal productivity index (PI) and water cut (WC) of each reservoir layer, before engineers can decide and manipulate the FCV flow area configuration of each reservoir flowing in a commingled setting. The current process of allocation using production logging is less efficient while layer-by- layer testing will cause deferments to a well's production. In offshore fields, the delay to production in order to make way for data acquisition is undesirable due to logistical difficulties. This project aims to build an optimizer to allocate reservoir parameters; PI and WC in commingled intelligent wells; and determine the most optimal setting for the FCV flow areas which will maximize oil production. This is built using data from downhole gauges, well modelling software and a multi software platform simulator (MSPS). The inbuilt algorithm in MSPS will allocate PI and WC to match simulated data calculated by a well model, to actual data from the field instruments with the lowest error possible. Once the PI and WC of each layer are known, FCV flow area settings can be configured to yield the optimal oil production. From the pilot on one well, the optimizer successfully helped engineers to increase oil production from 300 to 430 bopd in two months, while mantaining a steady yet maintainable WC increase of 11%, without any intervention costs or deferment. The allocated reservoir PI and WC allow engineers to strategize reservoir management plans specific to each producing reservoir layers, thus, improving the mechanism for reservoir surveillance.
Application of Thin-Bed Analysis in Reservoir Modelling to Unlock Further Development Potential of Thinly-Bedded Marginal Reservoirs
Authors: Chong E. E. , Azam M. N. , James P. B. , Rae S. F. , Flew S.
Published: October 2017

This paper describes how petrophysical thin-bed analysis is applied to an integrated static and dynamic modelling workflow to obtain a history match based on 3 years of production, for a series of relatively thin heterolithic reservoirs.

Previous reservoir simulation work based on conventional petrophysical interpretation for property modelling, indicated insufficient connected STOIIP and permeability-thickness to match flow behaviour observed from surveillance data. Therefore, an alternative thin-bed approach was proposed to address this fundamental reservoir characterization issue.

It is well known that across highly-laminated sandstone-shale intervals, the acquired log measurements of the sandstone laminations are adversely affected by shoulder effects due to inadequate vertical resolution of most logging tools. Furthermore, the resistivity of thin sandstones is suppressed by the high conductivity of silt-clay laminations which further compounds the problem. Thisleads tothe underestimation of reservoir properties and consequently, in the underestimation of hydrocarbon volumes and permeability-thickness.

The thin-bed approach utilises available core and high-resolution resistivity-based wellbore images together with open-hole logs. These are used as inputs to generate a set of petrophysical properties, via a log resolution enhancement (LRE) method, which are more representative of the reservoirs under study. The petrophysical improvements made, relate particularly to net pay thickness, porosity, permeability and saturation estimations.

This paper also demonstrates how thin-bed properties are propagated into the static modelling workflow, to produce a series of realizations which results in improved reservoir characterization, with more accurate in-place volumes and flow characteristics.

In practice, the application of thin-bed analysis requires careful refinement to 3D grid design so that the effects of thin-bed heterogeneity are captured to facilitate history matching in simulation. By integrating this thin-bed approach, an improved history match is obtained more efficiently and without significant application of local modifiers. This improvement further infers that thin-bed log analysis is much more appropriate than ‘conventional’ log analysis for thinly-bedded heterolithic reservoirs not only in this field, but potentially to many similar reservoirs in this basin, and elsewhere.

This work ultimately led toa successful infill drilling programme and opened up potential for extended development to include secondary recovery; as opposed to ad-hoc workover potential, as described in the original Field Development Plan.
Waterflooding Optimization: A Pragmatic and Cost-Effective Approach to Improve Oil Recovery from Mature Fields
Authors: Lu X. G. , Xu J.
Published: October 2017

This paper presents selected effective technologies and best practices to improve oil recovery from mature fields through waterflooding optimization. These technologies are proved practical, applicable and cost-effective. They can effectively facilitate further development of mature fields, which is more important than ever before in the current economical down-turn environment.

First, this paper summarizes and discusses several pragmatic approaches to optimize waterflooding of sandstone reservoirs. These methods have proved to be beneficial for expanding sweep, thus increasing ultimate recovery. Next, the authors introduce two methods to evaluate the effectiveness of application of these technologies, which can support both qualitative evaluation of the successfulness of the applications; and quantitative estimate of incremental recovery. Finally, this paper illustrates the best practices of each waterflooding optimization technology and the associated reservoir dynamic performance.

Waterflooding optimization aims at expanding volume sweep to recover bypassed oil in undrained areas or remaining oil in poorly swept areas. The main established approaches include (a) zonal water injection, (b) changing direction of fluid flow, (c) subdividing injection-production unit, (d) water shut-off to improve areal sweeping efficiency, and (e) cyclic water injection. These techniques are particularly applicable to multi-layer, vertically and laterally heterogeneous reservoirs at the high water-cut production stage. One best-practice example shows that converting comingled water injection into zonal injection has successfully arrested production decline, and resulted in an 11.8% incremental recovery. In another reservoir with 98% water cut and 54.5% recovery of changing injection direction by modifying well pattern has led to a 10% incremental recovery by. In still another example, subdivision of injection-production unit combined with infill wells has achieved incremental recovery ranging from 9% to 20%. A further case illustrates that, compared with continuous water injection, cyclic injection had led to reduced water production, lowered water-cut and increased recovery, and resulted in an incremental recovery of 1.84% EUR.

To conclude, maximizing reservoir sweep efficiency is the core step of waterflooding optimization. The techniques and best practices discussed in this paper possess both technical and economic viability. Effective application of those methods is an essential part of profitable reservoir management of mature fields.
Methodology of Compartmentalization Analysis for Modelling - Mereenie Field, Northern Territory
Authors: Nguyen T. T. , Nguyen L. A. , Perdomo G. E.
Published: October 2017

Explored in 1964 and first oil production launched in late 1984, Mereenie oil and gas field is the largest onshore oil field in mainland Australia. Although the production within the Eastern region has been in decline, an appraisal and development drilling project is expected to extend the life of the field. Therefore, a good understanding of dynamic compartmentalization through validation of material balance modeling would address current production planning and monitoring focused in the current oil production formation, Pacoota 3. This study could be the foundation for future development of the western part of the field.

Over 30 years of production and an enhanced oil recovery scheme which involved periodic injection from abundant gas within the upper formation, Pacoota 1; the producing oil formation has yet had any in-depth study of a dynamic compartment within the production time scale. The main objective of this study is to provide an analytical framework for dynamic compartmentalization. This framework was developed to capture the complexity in completions strategy and in the injection period. In total, six compartments across the Eastern Pacoota 3 formation were successfully identified and confirmed through modeling. However, uncertainties in structure and limited data at the West have contributed to production simulation's shortcomings.

It was found that compartmentalization in Mereenie is a combination of variables; those are a natural baffle, fault sealing, injection rate, and drainage radius; while structural faults have a primary role in decreasing the permeability and mobility of oil, causing discontinuity throughout the formation.