bluuebunny/crossref_metadata_2025 huggingface dataset:
Electric Powered Hydraulic Fracturing
Authors: Oehring J. M.
Published: October 2015

Traditionally hydraulic fracturing fleets are powered by over twenty large diesel engines up to 2,500 BHP each. By removing all diesel engines from a hydraulic fracturing site and replacing them with mobile turbine engine generator units, a fleet can be run completely on electric power. This technology was first deployed in 2014 in the Marcellus shale formation in West Virginia, and is the first fully electric, fully mobile well stimulation system completely fueled by natural gas.

The fleet runs on electric power generated by three natural-gas-fueled turbine engine generators. The power generated by the turbines then runs through switchgear and is stepped down to 600 volts (V) using transformers. At this point, the electric powered fleet is similar to a conventional hydraulic fracturing fleet, except that all the fleet’s diesel engines and transmissions are replaced by electric motors and variable frequency drives. Pumps, blenders, hydration, data van, and sand equipment are all completely electric powered.

The electric well stimulation fleet has shown great advances in environmental responsibility.

The fleet reduces refueling traffic, fueling costs, emissions, and sound. Electric powered hydraulic fracturing is an important step to conducting well stimulation in a more environmentally responsible manner.
Coupled Fluid-Solid Geomechanical Modeling of Multiple Hydraulic Fractures Interacting with Natural Fractures and the Resulting Proppant Distribution
Authors: Raymond S. , Aimene Y. , Nairn J. , Ouenes A.
Published: October 2015

The application of a new Material Point Method (MPM) approach to model the proppant distribution in a reservoir where hydraulic fractures interact with natural fractures is presented and validated with an Eagle Ford well. The new MPM approach uses particles to represent the slurry and its effects on the hydraulic and natural fractures. The particles are injected in the hydraulic fractures and their action causes the hydraulic fractures to propagate and interact with the natural fractures thus providing new pathways for the proppant to move away from the wellbore when optimal natural fracture orientations are encountered. Elementary tests, conducted with the new MPM approach show that fractures oriented in certain directions close to the hydraulic fracture orientation facilitate the proppant placement while other fracture orientations that are perpendicular to the hydraulic fracture or close to perpendicular direction appear to cause screen out. When using the new MPM approach on multiple interacting natural fractures with different orientations the same conclusions observed with one single fractures still hold and only those close to the orientation of the hydraulic fractures promote the placement of the proppant. The application of the new technology to an Eagle Ford well shows that the simulated proppant travels the farthest in the frac stage that is known from other methods and measurements to be the one with the best half fracture length. Furthermore, the examination of the simulated proppant concentration curve versus time shows striking similarities with the actual slurry concentration measured at the same well. These encouraging results show that the macroscopic modeling of proppant distribution using the new MPM technology could help improve our understanding of the complex hydraulic fracturing process and the resulting proppant distribution.
Simulation Study of Zipper Fracturing Using an Unconventional Fracture Model
Authors: Qiu Fangda , Porcu Matteo Marongiu , Xu Jian , Malpani Raj , Pankaj Piyush , Pope Timothy L.
Published: October 2015

In the past decade the industry has embraced unconventional resources; namely, shale oil and shale gas. After the initial drill-to-hold stage, multiwell pad drilling and stimulations are employed to exploit the acreage. Zipper fracturing is a technique that reduces the standby time (up to 50% reduction, when combined with the plug-and-perf isolation method). Because of this operational efficiency improvement, zipper fracturing has become one of the most common fracturing practices for unconventional reservoir stimulation. It has also been purported to increase production, which several authors have previously reported. There are also other studies showing no benefit of zipper fracturing on production performance.

In this paper we have used a complex fracture network model, which we refer to as the Unconventional Fracture Model (UFM), to study zipper fracturing. The model simulates complex (branched) fracture propagation, associated stress shadows, fluid flow, and proppant transportation in the complex fracture network. The model solves the fully coupled problem of fluid flow in the fracture network and elastic deformation of the fracture. A key difference between UFM and the conventional planar fracture model is being able to simulate the interaction of hydraulic fractures with preexisting natural fractures (also referred as planes of weakness). The UFM simulates interwell and interstage stress shadows and honors both sequential fracturing and zipper fracturing scenarios' geomechanical interaction.

In this paper, we present the results of a zipper and sequential fracturing study that includes the completion design optimization and the associated production performance in the Eagle Ford Shale. The study provides a workflow to optimize the completion and stimulation designs in pad development and to improve rate of return. The quantitative results show that zipper fracturing may not deliver a production benefit when compared with sequential fracturing and is a function of well spacing and perforation cluster spacing in a given area.
Developing The Business Case For Water Management Planning Integration
Authors: Neir Alyssa , Taylor Tekla
Published: October 2015

It is well documented that the cost of managing produced water amounts to a significant portion of the operating cost of an unconventional well over its lifetime. The greatest factor attributing to this cost is transportation, which can be addressed through logistical planning. However, effective logistical planning begins at the early phases of a project during reservoir engineering and drilling and production scheduling. But making the case for early phase water management planning can be challenging when there is limited field data and engineering priorities have not yet been established. This paper will look at how dynamic simulation modeling can be used to cost effectively optimize facility engineering while taking into consideration water management planning objectives.

Water management and facilities planning is an iterative process that is affected by many different inputs, ranging from environmental constraints to oil and gas production targets to power and energy demands. Putting these into a dynamic context that supports early phase scenario planning allows diverse members of the development team (reservoir, completions, facilities, water and environmental engineers) to understand the impacts of various constraints on the development schedule, well production, and capital and operating costs. Having this information in hand early in the project also allows the team to work together to quantify the impacts of various water management scenarios on exploration and production and conversely, the impact of the exploration and production decisions on future water sourcing and reuse opportunities.

Using a dynamic simulation modeling process to evaluate these scenarios and provide meaningful output and documentation can help management to prioritize their cost savings goals, balance trade-offs between water management and facility engineering objectives and communicate their business decisions to the necessary stakeholders. In addition to evaluating the engineering viability and economic impacts, a dynamic simulation model can also take into consideration the area-wide impacts to water, air and the ecosystem under various planning scenarios, and can be used to support play-based water management planning and permitting and industry collaboration.
Numerical Study of Production Mechanisms in Unconventional Liquid-Rich Shale Volatile Oil Reservoirs
Authors: Khoshghadam M. , Khanal A. , Makinde I. , Lee W. J. , Rabinejadganji N.
Published: October 2015

Liquid-rich shale (LRS) volatile oil plays exhibit several challenges to modeling and analyzing such as flattened produced gas oil ratio (GOR), complex phase behavior, rock properties and fluid flow influenced by pore proximity effects in nano pores. In this study we investigated multi-phase flow and the governing flow mechanisms in these resources using a new procedure to divide shale matrix into different sub-media and a new methodology to model well performance.

We have developed new correlations for modifying PVT properties in nano pores to incorporate the impact of nano-pore confinement on phase behavior. We have subdivided shale matrix into three zones, nano-pores, micro pores, and natural (macro) fractures along with propped fractures with distinctive PVT, rock compaction and relative permeability properties in a compositional simulation model. We have implemented logarithmically-spaced local grid refinement (LS-LGR) to track saturation and pressure changes around the hydraulic fracture. Results from our new method were validated against production data from several LRS oil wells in the Eagle Ford shale.

Our numerical model reproduced anomalous produced GOR's that have been observed in liquid-rich shale oil wells. The study showed that the main impacts of nano-pore confinement on phase behavior, rock properties and fluid flow are reduction of bubble point, enhancement of critical gas saturation and severe permeability reduction due to compaction. Delayed development of two-phase flow as a result of reduction of the bubble point pressure in nano-pores causes the "flat" GOR's observed in early stages of production. Enhancement of critical gas saturation delays mobilization of gas molecules in nano-pores and could extend non-intuitive GOR behavior further when reservoir pressure drops below the bubble point. We found that ultimate oil recovery could change more than 20% by permeability reduction due to compaction. The study revealed that the period of constant produced GOR depends on the volatility of the reservoir fluid and pore size distribution in the reservoir. For moderate-GOR oil reservoirs, the constant GOR duration is greater than for highly volatile oil reservoirs, as well as in reservoirs with a greater percentage of nano pores.

The methodology introduced in this study allows us to better model LRS volatile oil wells and to estimate EUR more accurately. These new correlations for modifying bulk PVT properties under confinement combined with numerical models enables reservoir engineers to understand better the complicated physics in LRS volatile oil reservoir performance.
Achieving Environmental Excellence: Through 3R Waste Management
Authors: Pratama Ageng Yoga
Published: October 2015

The expansion of company operational activities has produced a large increase in waste generation. All of this waste must be handled responsibly, and can be a considerable resource if managed effectively. PT Medco E&P – Rimau Asset has therefore been applying integrated waste management to manage its organic and inorganic waste. This program will improve the Company's ability to manage the environment, minimize environmental pollution, and utilize organic and inorganic waste as a resource.

Company management has a strong commitment to improving environmental management by emphasizing cleaner production through a "reuse, reduce and recycle" strategy for resources and waste. Organic waste-paper management has been applied through reusing paper or using both sides of paper, and using an online system as the standard means of communication or messaging among sections and departments, therefore, minimalizing the use of organic paper.

Waste recycling has also been applied to produce compost from organic waste. Furthermore, the compost has been used to replace chemical fertilizer for re-vegetation activities. Meanwhile, organic waste-paper is being treated for recycling organic waste-paper and converted into calendars, business cards, portfolio and envelopes.

These integrated waste management activities support PT Medco E&P Indonesia – Rimau Asset in solving the problem of organic and inorganic waste management and in addition have resulted in PT Medco E&P Indonesia – Rimau Asset being awarded the Gold Rating from the Ministry of Environment, Republic of Indonesia in 2011. PT Medco E&P Indonesia – Rimau Asset, was therefore the first E&P Company in Indonesia to be awarded the highest rating in environment management in Indonesia, a major achievement for the Company.
Cementing Optimization through an Enhanced Ultrasonic Imaging Tool
Authors: Su Hongsheng , Zheng Yongsheng , Qi Jing , Gao Fei , Guo Yabin , Taoutaou Salim , Wang Rui , An Yongliang , Guo Hongzhi
Published: October 2015

This paper demonstrates a successful practice on how to optimize centralizer placement through analyzing the measured casing standoff by an enhanced ultrasonic imaging tool in one underground gas storage (UGS) project in west China.

In the initial phase of the project, it was found that the cementing bonding in the dual casing section was commonly unsatisfactory in the production liner cementing. Factors that affect cementing quality, including fluid density/rheology hierarchy, pumped fluid volume, and pumping rate, were verified and excluded from consideration as possible causes for the bad bonding. With the measured casing standoff from one ultrasonic imaging tool, acentric casing resulting in bad mud removal was identified as the root cause. Centralizer placement was optimized with a specialized software simulation and, as a result, the subsequent drilled wells were cemented with excellent quality.

The imaging tool combines conventional ultrasonic pulse-echo techniques and flexural waveform attenuation measurement. Real casing standoff can be computed based on third-interface echo measurement. With the measured standoff, engineers can re-evaluate the original centralizer design and analyze whether there is a relationship between unsatisfied standoff and poor cement bonding, on basis of which engineers can improve centralizer placement for the following jobs to achieve better cementing quality.

Previously, engineers did not have a way to realistically evaluate their centralizer designs as the standoff results could only be simulated virtually. By adopting this new imaging tool, a new approach in the cementing design, execution, and evaluation cycle is established, which is proven to be an effective method to enhance cementing quality in the UGS project.
The Channel Fracturing Technique Improves Tight Reservoir Potential in the Ordos Basin, China
Authors: Anqi Li , Lijun Mu , Xianwen Li , Haihua Yang , Judd Tobias , Yaolan Liu
Published: October 2015

The Ordos basin, located in northwest China, has large known hydrocarbon reserves that represent unique reservoir challenges and require specific operational, logistical, and technical expertise. One of the immediate objectives for PetroChina Changqing is to exploit these low-permeability oil and gas sandstones of the Yanchang formation, and this is done through both vertical and horizontal wells types that include single-stage and multistage hydraulic fracturing treatments.

Historically, individual well productivity has been impacted by complex reservoir dynamics, uncertain subsurface properties, and identifying those areas where critical geological and reservoir factors exist in order to generate substantial production. However, most hydraulic fracturing treatments result in low production rates due to reservoir pressure being below the hydrostatic pressure gradient. Therefore, principal fracturing challenges include trying to engineer a highly conductive flow path that depends on fluid viscosity and stability to build geometry and transport proppant toward the fracture tip, while rapidly returning to the base-fluid viscosity to be flowed back.

Since reduced fracture conductivity and length were detrimental to well performance, a hydraulic fracturing technique that incorporates the creation of channels within the fracture was deployed. This technology optimized reservoir inflow performance through a specified engineering workflow that requires specific equipment and pumping controls with fluid and fiber technologies. These channels created infinite-conductivity paths for fluid to flow from the reservoir to the wellbore, resulting in higher well productivity.

The deployment and application of this technology included 65 treatments performed on five vertical and five horizontal wells in oil blocks and two vertical wells in a gas block. Production performance for all oil wells treated with the flow-channel fracturing technique had initial production index figures being 2.4 times the field average and those wells continue to be upper performers when compared to 180-day accumulated production figures. For the gas wells, 4 to 5 times initial gas production rate was achieved when compared to the average offset wells. In all well cases, channel fracturing increased operational efficiency while resulting in no screenouts.
Buffer Basin Cleaning; Combination Between Operation Excellence and Environmental Compliance With 3R (Reduce, Reuse, Recycle) Approach
Authors: Siboro M. , Witono J. A. , Rusdi R. K. , Hartoyo O. S.
Published: October 2015

In 2012, Total E&P Indonesie (TEPI) decided to conduct cleaning of Buffer Basin. Buffer Basin is an open concrete basin connected to downstream of API Separator (integrated system in New Oily Water Treatment/ NOWT, Senipah Terminal). Originally, Buffer Basin was designed to handle fluctuation/ excessive flow of incoming oily water from process (e.g. from separator and storage tank draining). The biggest impact of isolating buffer basin is stopping liquid production of all TEPI sites. This generates long discussion and trial before the implementation. Consequently, accumulations of sludge/ sand were affecting not only the quality of the discharged produced water but also the health of people/ personnel due to the massive generation of BTEX (Benzene, Toluene, Ethyl Benzene, and Xylene). The key factor of Buffer Basin cleaning was the successful re-activation of old OWTU to temporarily bypass the incoming oily water treatment. During this temporary period, no process shutdown was experienced which may impact occurrence of production loss. The oily water treatment operating cost was reduced by approximately 50% due to reduction on chemical injection. The quality of disposed water to environment is still below permit requirement. Meanwhile, cleaning the Buffer Basin itself was challenging due to huge amount and various properties of sludge/ solid, highly impacted by weather, hazardous material exposure, etc. The sludge was treated using Sludge Oil Recovery (SOR) process resulting in 4 derivatives/ products (recovered oil, solid, emulsion, and oily water). To comply with environment regulation, upon relevant Government Bodies approval, TEPI in cooperation with licensed Contractor used 3R (Reduced, Reuse, Recycle) approach to manage the waste. The solid waste was processed to become fire resistant bricks which can later on be used as heat insulation. The emulsion was used as synthetic fuel and become energy source for making the bricks. The water was treated in oily water treatment unit prior disposal to environment. Recovered oil was sent back to TEPI's storage tank. The project was completed and all the challenges were overcome.
Relative Permeability Modifier (RPM) as Chemical Diverter in Bullhead Matrix Acidizing Treatment
Authors: Salman Hayatullah M. , Ridwan Ridwan , Raihan Raihan , Meifresia Lisa , Kurniawan Hafidz , Napitupulu Benni Hermanto
Published: October 2015

Matrix acidizing treatments are widely used for stimulating oil producing wells in the Zamrud field because of damage caused by scale plugging. The success of this matrix acidizing treatment depends on the uniform distribution of the treating fluid over the entire hydrocarbon-producing zone (Hill et al. 1994). Most oil producing wells are not homogeneous and contain sections of varying permeability—when fluids are pumped into a well, they naturally tend to flow into the zone with the highest permeability or less damage (Eoff et al. 2004). Being able to completely acidize the interval is a major problem.

Historically, mechanical techniques using packers has been employed by this operator to control the placement of acid fluid into the wellbore. One of the greatest challenges is that, although mechanical techniques are very effective, they are more time consuming than chemical techniques. Mechanical techniques divert treatment fluids from the wellbore; however, there is no control once the fluid enters the formation. On average, from four wells that were acidized using mechanical techniques, the post production performance was not satisfying—no production increase.

For many years, relative permeability modifiers (RPMs) have received a great deal of attention from the oil and gas industry. RPMs offer the option of bullheading an acid treatment without zonal isolation, and they are also designed to decrease water production with little or no decrease in oil or gas production. It is a solids-free diverter, opposed to the plugging mechanism of typical particulate diverters; it can be used for sandstone and carbonate formations with temperatures of 80 to 350°F and a permeability of approximately 6 darcys. The RPM system is placed in alternating stage(s) with the acid throughout the entire treatment. The first stage containing RPM predominantly will enter the most permeable area; it will change the effective permeability of the zones where it is adsorbed, diverting the following acid stage(s) to other zones or sections of the rock. Furthermore, in rock containing significant proportions of sandstone-type lithology, the water permeability of the treated zone is decreased permanently, resulting in post-treatment reduced water production from the treated zone. This paper discusses the geological and reservoir parameters of the wells, job design consideration, and post acidizing results when using RPM as a chemical diversion technique. Field results show significant improvement of post-stimulation production after combined acid with RPM systems were implemented in comparison to offset wells acidized with mechanical techniques in the same reservoir and at the same level.
Adapting Fracture Corridors and Diffuse Fractures in Single Porosity Model of Ujung Pangkah Carbonate Reservoir
Authors: Saputra Rini , Hidayat Azalea , Rahmanto Wahyu Agung
Published: October 2015

A practical method to adapt fractures both micro and macro as flow enhancing properties in a single porosity model is introduced to simulate Ujung Pangkah fractured carbonate reservoir. This approach is taken because dual porosity modeling attempt fails to explain the behavior of many wells which experience early water breakthrough and/or excessive water production in Ujung Pangkah field.

The enhancement factor term is used to define the degree of permeability enhancement by diffuse or micro fractures. At well location, the enhancement factor can be determined by the ratio of production test to the production of matrix-only model. The enhancement factor 3D distribution is derived from well data and seismic minimum curvature attributes as trend. Fracture corridors correspond to macro fractures in the order of meters extending vertically and/or laterally. As normally scattered spatially, fracture corridors cannot be modeled in a discrete fracture network model which is the integral part of dual porosity model. Some wells show behavior anomalies, such as rapid, early water breakthrough with excessive water production in unlikely location. It is observed that the location of these anomalies coincide with the fracture lineaments derived from the seismic incoherency attribute.

As the fractures are well characterized, diffuse fractures as permeability enhancement and fracture corridors as high permeability streaks, the further improvement of history match is then easily achieved by calibrating two other key parameters; relative permeability curves and aquifer strength. The relative permeability is calibrated to the shape of fracture relative permeability. Oil rate match is greatly improved. Water rate match is achieved by placing adequate aquifer strength.

Reservoir dynamic of Ujung Pangkah carbonate fractured reservoir can be simulated as a single porosity model with permeability enhancement adapted from two types of fracture distribution. Diffuse fractures enhance the overall permeability and fracture corridors dominantly influence flow dynamic in certain local area. Compared to dual porosity model, adapting fractures as permeability enhancement in single porosity model is more practical, more efficient in simulation run time – computational cost.
Innovative Well Cementing Applications by Using Large Particle Sizes of Cement Additives
Authors: Doan Angela , Brandl Andreas , Vorderbruggen Mark , Leonard Daniel D.
Published: October 2015

Water-soluble cellulose based polymers such as hydroxyethyl cellulose (HEC), methylhydroxyethyl cellulose (MHEC), and carboxymethylhydroxyethyl cellulose (CMHEC) are commonly used additives to control important cement slurry properties like fluid loss, free fluid, and slurry stability. They typically hydrate quickly after contact with the mix water resulting in instant slurry viscosification and potential mixing difficulties especially at higher loadings. Adding cement dispersants to the cementing system design can facilitate slurry mixing but this does not always work out as expected. Sometimes incompatibilities between the dispersant and the other additives result in even more difficult slurry mixing. Furthermore the addition of dispersants to compensate mixing problems can enhance thermal thinning leading to severe settling issues once the slurry is exposed to the elevated downhole temperatures in the wellbore.

To overcome these challenges, the use of large particle size cement additives to lower the surface mixing viscosity and the effect of important slurry properties were studied. The cement fluid loss, free fluid control, and slurry rheology performance of large particle size polymeric additives were evaluated in cement slurries. Different particle sizes for polymeric additive were tested in assorted cement densities and temperatures. Cement testing procedures, lab test results, and a case history is presented and discussed.

The study demonstrates that the hydration of the cellulosic polymers is delayed as particle size of polymeric additives increases. It could be concluded that the use of larger size cellulosic polymers greatly facilitates slurry mixing, requires less mixing energy or reduces slurry mixing time, and results in a lower initial slurry rheology without negatively affecting other slurry properties (in some cases the fluid loss performance was even significantly improved).
Experiment and Simulation Research on Hydraulic Fracture Propagation Characteristic under Interface Layer Influence
Authors: Kangxing Dong , He Liu , Suling Wang , Minzheng Jiang
Published: October 2015

Key factor to develop shale reservoirs effectively is formed stimulated reservoir volume (SRV) of complex fracture network. When hydraulic fractures intersect with interface layer or natural fracture, fracture may slip along the interface, that provides a condition for the formation of fracture network. Bi material shale reservoir fracture mathematical is established in this paper, the critical conditions of shear sliding was studied by using elastic theory. Physics experiment is constructed by using the similarity criterion of the interface layer effect on hydraulic fracture extension, the influence of horizontal differential principal stress, interface friction coefficient and rock tensile strength on the fracture propagation is studied by hydraulic fracture experiment. This paper established finite model of bi material shale reservoir by using RFPA2D software, the influence of horizontal differential principal stress, interface friction coefficient and rock tensile strength on the fracture propagation is simulated. Analysis results show that: In the condition of low horizontal differential principal stress, low interface friction coefficient and high differential rock tensile, shearing slippage damage tend to happen, the fracture will continue extend along the direction of the maximum principal stress when it meted flaw after extend along the interface. On the contrary, fracture tend to cross the interface. This research has important theoretical value and practical significance to network hydraulic fracturing of shale reservoir.
Development of a Trilinear Flow Model for Carbon Sequestration in Depleted Shale
Authors: Chen Z. , Liao X. , Zhao X. , Lv S. , Dou X. , Guo X. , Li L. , Zang J.
Published: October 2015

While many researchers are trending to seek the conventional geological sequestrations for CO2 storage, like saline aquifers, depleted conventional hydrocarbon reservoirs, and unminable coal seams, only a few are interested in depleted shales for safety and economic reasons. Thus, for reservoir engineers, lots of work needs to be done to better this situation. First and foremost, it is an urgent issue should be settled how to estimate the CO2 storage capacity in depleted shale.

In this paper, a new analytical method to estimate CO2 storage in shale wasdeveloped. First, a trilinear flow model was proposed for the injection well, namely a multiple fractured vertical well (MFHW), at a constant injection rate. The model incorporated with multiple mechanisms including Knudson diffusion, gas adsorption, and effect of stress-sensitivity. Then, the transient pressure solution of injection well is solved by applying mathematical methods. Subsequently, CO2 storage capacity was evaluated according to the transient pressure performance of injection well. After that, model verification as well as sensitivity analysis was conducted. Finally, we applied the proposed method into a case derived from the New Albany Shale, which has been proved to be a promising candidate for CO2 storage.

The results show that a good agreement exists between our analytical results and these numerical solutions. The average difference is about 2.57%, which shows our methodology is reasonable. Further, it only takes about 10s CPU times with 100 time step by employing the proposed approach to estimate the CO2 storage capacity of the study area in the New Albany Shale, which indicates the new approach is rapid. Additionally, results of sensitive analysis show that as stress-sensitivity coefficient, adsorption index, and Knudsen diffusion coefficient increase, CO2 storage capacity increases. As storage ratio increases, CO2 storage capacity decreases.

This meaningful work provides a new angle on estimation of CO2 storage capacity, which is beneficial to exploit the residual depleted shale reservoirs as well as cut CO2 emission.
History Matching with Ensemble Kalman Filter Using Fast Marching Method in Shale Gas Reservoir
Authors: Leem Jihun , Lee Kyungbook , Kang Joe M. , Park Yonjun , Park Jihye
Published: October 2015

In case of shale reservoirs, there are lots of uncertainty parameters: matrix permeability, fracture permeability by hydraulic fracturing, enhanced permeability surrounding fractures, fracture half-length, vertical enhanced ratio, horizontal enhanced ratio, and porosity. Reasonable uncertainty quantification enables us to predict shale reservoir performance. Ensemble Kalman filter (EnKF) is one of the most reliable history matching method. However, EnKF has the limitation of simulation time because each prediction step requires forward simulation as the number of ensemble members. Larger size of a field is simulated, much simulation time is consumed. Fast marching method (FMM) is able to reduce simulation time and shows reliable result of shale gas fields compared with other simulators. Therefore, we ropose the concept of unification of EnKF and FMM for reliable and fast.

To validate the advantage of the proposed method is compared with EnKF using a conventional forward simulaotor. Also, the proposed method is coupled with distance-based generalized sensitivity analysis (DGSA) to select sensitive model parameters. FMM-EnKF using selected parameters is useful when it is difficult to obtain reservoir uncertainty information. The three methods, the standard EnKF, FMM-EnKF using all parameters, and FMM-EnKF using selected parameters, are compared by history matching time, distribution of uncertainties, and cumulative responses.

The standard method and the proposed method shows decline in width of uncertainty after history matching. However, the proposed method completes history matching faster than the standard EnKF. Most of all, the proposed method using selected parameters decreases the width of cumulative responses compared with the proposed method using all parameters. Therefore, this method is going to contribute the section of history matching and prediction of future production.
Extracting Lessons Learned of 35 Water Shut-off Jobs in Mature Fields to Improve Success Ratio of Water Shut-off Job
Authors: Permana D. , Ferdian G. , Aji M. , Siswati E.
Published: October 2015

Increasing water production in a mature field means an increasing burden of operating cost because that water production must be processed and treated before it is discharged or injected1. One common solution to overcome this problem is conducting water shut-off jobs which consist of mechanical and chemical water shut-off. Mechanical water shut-off is preferred to be carried out over chemical water shut-off because of lower costs. An example of mechanical water shut-off is using cup packer, squeezing-cement, and reperforating over a shorter interval.

In Central Sumatra, there were approximately 35 mechanical water shut-off jobs executed from 2010 – 2012. Those jobs were varied from mature fields having different geological conditions, recovery mechanisms, drive mechanisms, and operating-rate conditions which may be influencing the rising of current oil water contact (COWC).

Based on the completed water shut-off jobs, some lessons learned were to have perforation interval above current oil water contact (COWC), have good historical water shut-off performance at surrounding wells, have good production performance at surrounding wells, have good structural location, and have by-pass oil identified from CO/RST log if it is below COWC. Those lessons learned will be applied to upcoming water shut-off candidates.

This paper further explains of some lessons learned which will be useful for selecting candidate of water shut-off jobs and compares the result of water shut-off jobs after implementing lessons learned which significantly increased its success ratio and oil gain.
The Success Story of Light-North Area of Roger Block: Continuous Exertion to Increase Electrical Submersible Pump Performance through Rectifying Design Process to Resolve MDSS Problem
Authors: Dewi Cintani Kusuma , Rahman Fatkhur , Maulana Prapta
Published: October 2015

Mud-Debris-Sand-Solid (MDSS) is identified as second top contributors for 2011-2012 ESP failures in Light-North Area, a potential light-oil-field in Roger Block. It caused 20% total failure, with sand and debris as top contributors. Loss Production Opportunity is around 39 MBO from total 25 cases; rig services for reactivation costed averagely 12.5 MUSD/job. It's seen necessary that workflow process in pump design must be improved to treat MDSS issue more effectively to avoid reoccurrence.

The existing design process possesses numerous aspects to be considered. The team decided to place more emphasis on items that might give high impact in enhancement. Rectified workflow design process is then generated, this present as standard guidance on defining mitigation, proactive, and reactive recommendations. All recommendations are managed by prioritization based on the new-workflow with less effort yet giving big impact. As part of the study, 8 wells with historical MDSS and last run-life less than 180 days were selected to be monitored. Once experiencing down, the new-workflow is then applied.

Every mitigation step in this work is obviously not new, but executing them in a random sequence can only waste time, effort and certainly money. With the continous drop of crude price, proper mitigation is a simple formula to optimize our resources and hence results in an efficient yet safe operation.
Novel Fracturing Fluid Significantly Increase Production in Sulige Tight Gas Field
Authors: Yang Zhanwei , Yang Lifeng , Duan Yaoyao , Wang Yonghui , Tian Zhuhong , Lu Yongjun
Published: October 2015

Sulige gas field located in Ordos Basin is the largest gas filed in china. Eastern block of this field which consists more than 1000×104 MMscf geological resources belongs to tight gas reservoir. Due to low gas saturation, less than 10% porosity, around 0.05 mD permeability and below 0.85 pressure coefficient, stimulation treatments is necessary in order to get economic production. Development speed of this block had been seriously affect because of Significantly lower single well production than other parts of the Sulige gas field. Low concentration crossed-linked guar fracturing fluid is now commonly used in this area. As small size pore throat, high clay content and water lock, this gas deposit is sensitive to treatment fluid, thus the flowback time of fractured well is very long and production is generally low. In this paper we introduce a new fracturing fluid which can be crossed-linked in acidic water-based fluids. This fracturing fluid contains a kind of cellulose, which is completely soluble with no residue. Cellulose had been used as addition agent in drilling and completion fluid twenty years ago, therefore application range was greatly limited as bad performance stability. New cross-linked agent and additives solved this problem. Because of being compatible well with the reservoir fluids, the damage of fracturing fluid is relatively low. Proppant carrying capacity of this new fracturing fluid can be compared with low concentration crossed-linked guar fracturing fluid. The new fluid has been used in 6 vertical wells, which have 100% treatment success-rate and 8.6×104m3/d average production rate. Comparing with the nearby wells which had the same pay formation and were fractured with the similar fracture treatment scale by low concentration guar fracturing fluid, the flowback time was shortened by 53% and gas production was doubled. In conclusion, this new fracture fluid can reduce treatment time, cost and increase gas production.
A Structured Energy Architecture Performance Index Approach in Managing the Challenges of Indonesia's Energy Sector
Authors: Budiarso Budiarso , Adrian Herman , Gunawan Widy , Nalle Herbert , Pramudita Reza , Tanuwijaya Ryan
Published: October 2015

Since the industrial revolution in 18th century, people were always looking for more economical, more sustainable and – recently put into concerned about – more eco-friendly energy supply to fuel up the world economic growth. However the fact showed that the energy we consumed even became less affordable, less secure and less environmental sustainable for the last decades.

World Economic Forum collaborating with Accenture formulated Energy Architecture Performance Index (EAPI) to provide more structural approach in understanding the condition of each country's energy system. Energy Architecture is defined as the integrated physical system of energy sources, carriers and demand sectors that are shaped by government, industry and civil society.

Driven by the boundary constraints of economic development, geography and prosperity, countries are striving to find new and innovative ways to meet the demands of their energy system. The transition pathway from the current Energy Architecture to the new will look different for each country, with energy system objectives planned according to the trade-offs and complementarities surrounding the core imperatives of every energy system: managing risk to energy supplies while ensuring a country's economic, social and environmental well-being.
Estimation of Time of Peak Gas Production in Coalbed Methane Wells using Production Data Analysis
Authors: Salmachi Alireza , Darby Jake , Yarmohammadtooski Zahra
Published: October 2015

For coalbed methane (CBM) wells with rising gas production, time to reach peak of gas production and peak gas rate are two fundamental features of a production profile. This paper investigates the time of occurrence of peak of gas production in CBM wells using production data analysis (PDA).

The methodology is simple and requires gas rate and flowing bottom-hole pressure (BHP) data. Signatures of time of peak gas production are obtained using time derivative of square of BHP over gas rate. Signatures are obtained for constant and variable bottom-hole pressure operational constraints. Derivative of square of BHP over gas rate with respect to time is calculated for observed production data. Then, plot of this derivative versus production time is constructed for the CBM well. Finally, the plot is extrapolated to a time at which the signature of peak production appears. This time is estimated to be the time of occurrence of peak of gas production. The production data for a CBM well in San Juan basin is analyzed using this technique to demonstrate the signature and the estimation of time of peak gas production.

The accuracy and correctness of estimation depend upon quality of production data, goodness of fitted functions used in this approach, and time interval between time of peak gas rate and observed production data. The signatures of time of peak production introduced in this paper can contribute to production forecasting of the negative decline portion of the production profile of CBM wells.
Economic Success in Complex Channel Sand Reservoir Development Driven by New Technology
Authors: Yang Liuhe , Zhao Yongsheng , Nie Chaomin , Guo Xijia , Sun Guoqing , Yu Xiaoning , Wang Fei , Xu Chonghui , Fu Zairong , Chen Chengqian , Xu Tianyun , Wen Xin
Published: October 2015

BZ29-4 is a new development field located in the southern part of Bohai Bay which is the main offshore block for CNOOC (China National Offshore Oil Corporation). Distinguished from others, BZ29-4 is featured by braided fluvial sand deposition and multiple post diagenesis tectonic movements. Reservoir's scattering distribution and micro faults' fully deployment become big challenges for field development. Restricted by technic capacity and budget management, BZ29-4 was kept as a reserved field in operator's strategy.

According to CNOOC's objective – obtaining 35 million m3 production in 2015, and scientific innovation, a new drill campaign is proposed in 2012. Several new technology is adopted. Boundary detection technic provides detailed profiles overcoming the difficult about unclear oil/gas and oil/water contact position. By following the environment requirement, a new sourceless density/porosity measurement is applied. Rotary steerable system demonstrates high adaptability in disconnected and isolated sand bodies and eminently improves drilling safety. These technology with advance data transition platform, multiple discipline research staff involves in the drilling, delivering real time support and reducing the gap between study achievement and execution.

Through considerable data assessment and feasibility study, an innovative dynamic exploration strategy is used in this development project. Instead applying the whole suit technic in every well, the combination of new technology is optimized according to each well's particular challenge. Besides, well deployment and plan trajectory are timely adjusted in assistance of the fresh drilling result. By this means, the economic portfolio for BZ29-4 is significantly rationalized and 8.85 million USD has been saved in field development stage.

Until the end of 2013, 15 horizontal wells has been drilled in this field. With the new technology application, net-to-gross (NTG) is promoted to 100% and drilling efficiency increases 80.9%. After all these wells are in production, the daily output reaches to 295t/d exceeding operator's expectation by 51% and the recovery factor elevates to 29.9% leading in all CNOOC fields.
Integrated Offshore Mature Field Revitalization in Asri Basin, North Business Unit Area, Southeast Sumatra, Indonesia
Authors: Waskito Lucky Bagus , Widiatmo Reza , Gunawan Heri , Pengxiao Sun
Published: October 2015

Asri basin has been on producing since July 1989, currently there are 9 fields has been developed with strong water drive reservoir driving mechanism characteristic. Peak production was 196,000 bopd, presently producing 34,000 bopd with water cut of 99 %. Challenge faced in the studies had to deal with mature reservoir, declining production, depleted reservoir pressure, unrealistic recovery factor and the need to enhance asset value. Beyond that complexity, commercial challenge in rejuvenating the field becoming more critical due to falling oil prices.

This paper present how integrated evaluation of mature offshore oil field performance and investigated various scenarios could add more value to the asset. Water flood, water shut off, and single field revitalization project has been implemented and it shows satisfaction result in reducing and maintaining production decline rate even increasing oil production volume. Recommendations also made to sustain and gain oil production by implementing successful projects to other field and also trying to implement Polymer Injection pilot project in Indonesia.

The important thing in revitalizing a mature field is to define a customized asset evaluation approach to managed large amounts of data and identify the most important mechanisms in creating value-added solutions, while minimizing costs. The team captured this through innovative systems planning and operation, displacing the traditional lab-to-field R&D search in that multiple options were generated from within functional technology contributions.

As expected, the results of full project implementation are satisfying. Depleted reservoir problem in major field producer has been solved by water flood project, the pilot project has been conduct in 1999 and shows great result in increasing oil production rate, within 2 years the oil production rate increase from 2,000 bopd to 12,000 bopd. Another project has been implemented in this major field is facies re-analysis, from this analysis new map are created, therefore new point of view can be extracted to support more comprehensive analysis, and the new analysis are very useful to gain oil production. Marginal field also part of the revitalization program in Asri Basin, in 2012 rejuvenation project has been conducted, and the result shows 4 times oil rate incremental, from 264 bopd to 908 bopd. One of other successful project is water shutoff, 2 wells are implemented for this project, and it can reduce water cut up to 17%, from 99% to 82% water cut. Those successful projects will be implemented for other field in Asri basin North Business Unit Area to Sustain and Gain Oil Production Rate.