bluuebunny/crossref_metadata_2025 huggingface dataset:
SPME Method Development for the Determination of Aliphatic Amines in Industrial Waste Water
Authors: Alghamdi Talal M.
Published: May 2016

In the presence of dissolved oxygen in the water inside a pipeline, the oxygen attacks the steel to form iron oxides. To prevent this, corrosion inhibitors are added to the crude oil streams. These chemicals are amines-based that form a film to coat the steel and prevent it from contacting the oxygen. Amines residuals should be monitored in the system and this is classically done by liquid-liquid extraction (LLE) of amines followed by colorimetric determination using spectrophotometry.

In this work, solid phase microextraction (SPME), a novel extraction technique that uses no solvent, was used as a sample preparation technique to isolate the amines from the complex sample matrix and then the gas chromatography (GC) system was used for separation and quantification of amines. A flow-through system was used to simulate the process of flowing streams in pipelines during oil production.

A method was developed to determine amines residuals at the lowest detection limit possible at the optimized conditions such as solution pH, ionic strength, and sand contents. It was found that residuals can be determined as low as 1ng/mL using the GC system equipped with a flame ionization detector (FID). This method was developed in the lab using a model to simulate the flowing streams and containing synthesized waste water.

This method is an environmental friendly technique that will minimize the use of hazardous solvents and therfore the need for the proper disposal of them. Also it does not require pretreatment steps of samples or many reagents to be used in the extraction process of amines residuals. Finally, it will provide more precise results in a timely manner for better and quicker actions.
Drilling with Casing Technique Successfully Overcome Massive Thief Zone
Authors: Agustina Diah , Tanjung Erwindo , Taufiqurrachman Hafidh , Won Keith , Zega Delfin
Published: May 2016

The Lima field, located offshore in North West Java Indonesia, encountered major challenges to both drilling and cased off problematic zone during running casing operation due to severe lost circulation conditions. Specifically, severe mud losses in the major loss zone were recorded in Pre-Parigi formation. The operator has experienced massive loss problems while drilling the 8-1/2inch section. Unsuccessful sidetracking operations with conventional drilling technique has urged operator to look for alternative drilling methods to caseoff the massive thief zone.

The drilling with casing system has been identified as one drilling technique that may repair the troublesome thief zone. This non-retrievable system, which utilizes casing as drill string, allows the string to immediately be cemented in place once targeted depth is achieved, hence eliminating the risk of casing tripping failure through massive lose zone with conventional drilling method. The special designed aluminum crown casing bit is drillable by subsequent section conventional bit without additional clean out trip.

This paper will discuss the planning, implementation and finally the results of 7 inch drilling with casing technique through the problematic Pre-Parigilost circulation zone.
Lessons Learnt from Water Shutoff of Horizontal Wells Using Inflatable Packers and Chemicals in Ghawar Field of Saudi Arabia
Authors: Sharma Hemant , Duarte Jorge , Mufeed Eid , Turki Saadoun , Vielma Jose R.
Published: May 2016

Due to the advancement of technology and improved capabilities of drilling horizontal wells, producers and injectors are now commonly completed with long horizontals to expose large reservoir areas. For the reservoir pressure maintenance, the most prevalent means is by using water injection. This injected water, while helping in pressurizing the reservoir, becomes a curse when it starts to produce with the oil. In addition, as the transmissibility of the water is higher than the oil, water breakthrough is a major challenge facing the oil industry. Various techniques are available and being used worldwide to control/reduce this produced water; however, controlling water production by performing water shut-off (WSO) in horizontal wells is more complicated and challenging than in vertical wells.

To control water production in horizontal wells, isolation of the wellbore using inflatable packers in open/cased hole completion and capping with cement has shown little success in the past.

Therefore, another technique was attempted to control water production in horizontal oil producers by using mechanical means to isolate the wellbore and chemical means to isolate the matrix/fissure, which forms a permanent barrier and reduces water production. The selection criterion for mechanical isolation and type of chemical suitable for the formation is a tedious task for the petroleum engineer. Most of the time, the vendor's data that is available is being used and applied for the field application, which shows a low success ratio.

In this paper a brief overview has been presented, taking into account two wells from Ghawar field in Saudi Arabia, where a combination of wellbore isolation using inflatable packers and matrix/fissure isolation using an organically cross-linked polymer (OCP) system were performed. The candidate selection criteria, job criteria, planning, execution, and post-job evaluation will be discussed.
Physical Modelling of In-Depth Fluid Diversion by "Gel Dam" Placed with Vertical Well
Authors: Li Junjian , Liu Yuzhang , Li Yikun , Wei Falin , Lv Jing
Published: May 2016

In view of the ineffective cycling issue of injected water through the high permeability zones during water flooding process in positive rhythm reservoirs, the gel dam in-depth fluid diversion technique is proposed. The technique first promoted the injection of gel by horizontal or sidetracking wells drilled in the more permeable and strongly swept zones of thick positive rhythm reservoirs. The injected water then will bypass the "gel dams" and be diverted into the upper unswept or poorly swept low permeability zones. As a result, the swept efficiency and oil recovery of the upper low permeability zones can be both increased.

Gel dam placement method can be enhanced the oil recovery both in the laboratory experiments and numerical simulation technology, but the use of new drilling horizontal wells for gel dam placement accompany with certain technical and economic risks; In order to reduce risk, to explore the law of horizontal well gel dam placement, we proposed the use of the crossing straight well set to place the gel dam for Daqing Oilfield, which is consistent with the current research status. Straight and horizontal wells gel dam placement have the similar principles, but there are some differences, how to use a crossing well to place the gel dam should be further study to improve the development effectiveness.

The physical modeling experiments of gel dams in a positive rhythm formation and in a point bar sand body are conducted in the 3D physical model. The results of the experiments indicated that, with one or two gel dams, the sweep volume and ultimate oil recovery were both increased greatly, and the water cut ascending velocity was decreased. Compared with the physical model with horizontal gel dam, the ultimate oil recoveries of those with gel dams decrease by 8.1,but the oil recvoery is still 7.6% higher than waterflood. By vertical well "gel dam" in-depth fluid diversion technique, the difficulties in the in-depth placement of plugging agents will be solved, risk has been reduced and the swept efficiency of positive rhythm reservoir can be increased significantly.
A Successful Application of 3D Seismic Attributes in Exploration for Eolian Stratigraphic Traps in Central Saudi Arabia
Authors: Hu Herbert , Al-Zahrani Mohammed Saeed , Al-Mahmoud Khalid
Published: May 2016

The purpose of this presentation is to demonstrate the successful application of 3D seismic attributes in exploration for Permo-Carboniferouseolian stratigraphic traps in central Saudi Arabia. To explore for these traps, we have integrated regional geological studies and rock property analysis, and tied these to the seismic attribute response.

Permo-Carboniferous eolian reservoirs are the primary objective for oil and gas exploration in central Saudi Arabia. Due to the nature of the mixed fluvio-eolian setting, this is a very challenging target, especially for stratigraphic traps. The eolian setting comprises a complex mix of depositional systems including eolian ergs, ephemeral streams, and ephemeral (playa) lakes. Eolian sand dunes and sand sheet deposits are the two main reservoir facies, while lateral facies changes result in the primary up-dip seals.

We carried out detailed well-to-seismic correlations at the reservoir level and found that the following seismic attributes were useful in exploring for these stratigraphically trapped eolian reservoirs:Reservoir thickness and quality:sum of positive amplitude over the target interval,isochron from Early Triassic to Early Permian,isochron from top to base of the target,frequency decomposition,acoustic impedance inversion, anddeformation of seismic wavelet.Up-dip seal: Sum of the negative amplitude over the target interval.Hydrocarbon potential: AVO/AVA inversion.

Exploration results in the study area indicate that the above mentioned seismic attributes correlate very well to changes in geologic environment, and to log and reservoir properties. The integration of 3D seismic attributes with regional geologic studies and existing well control has been very successful in exploring for eolian stratigraphic traps in central Saudi Arabia.
Multiple History Matching and Well Placement Optimisation in a Mature Field Using a Streamline Approach
Authors: Raniolo S. , Bilancio D. , Dovera L. , Mezzapesa D. , Galibert S.
Published: May 2016

The paper presents an application of an innovative workflow for multiple history matching. Initially streamline-based simulations are used to rank multiple geological images and to efficiently identify representative models. Afterwards, the selected realizations are fully simulated and multiple history matching is achieved through the application of genetic algorithms.

The workflow has been implemented on a North African field whose production started in 1996. The main hydrocarbon reservoir is a Triassic sedimentary series developed in a fluvial environment characterized by high heterogeneity and uncertainty. Such uncertainty has been captured by generating more than a thousand alternative reservoir models by varying key geological parameters. For each realization, streamline simulation was performed and the heterogeneity has been measured based on flow capacity-storage capacity plot. Streamlines simulation requires only few minutes to solve the entire set of models. Cluster analysis was used to select five models with different heterogeneity. History matching calibration has been set up on the reduced number of realizations using genetic algorithm to speed up and automate the process.

The final output of the workflow is a set of alternative models properly matched that represent the ideal suite to estimate the uncertainty in forecast and to evaluate infilling opportunities.

Well placement optimization has been then implemented all over the different geological scenarios.

The application demonstrated that the innovative workflow allowed managing more than a thousand reservoirs models in a very short time, to efficiently select representative realizations and to speed up the history matching process. Moreover, dealing with multiple history matched models put the basis for a robust estimation of future production together with a more reliable evaluation of new infilling opportunities.

As a result of the study, two over three approved wells have been already drilled and put on stream with positive results, in line with the predictions.
Asset Integrity Challenges in Oil & Gas Process Facilities
Authors: Al-Sulaiman Saleh , Sardesai Vinayak , Murthy Hari Srinivasa , Reddy N. Harinadha , John Reji P.
Published: May 2016

Managing asset integrity is a complex activity in surface production facilities of an oil industry. Process equipment in an oil production facility is exposed to various damage mechanisms that may be active due to the presence of contaminants in the process streams.

Proper material selection, maintenance programs, inspection monitoring and repair are the standard components of the Asset Integrity Management Process. The conventional way of approaching the problems caused by damage mechanisms such as Hydrogen Induced Cracking (HIC) and Stress Corrosion Cracking (SCC) in Pressure vessels is by way of repairs or replacements. Black powder deposits are also causing increasing concerns due to fouling and severe corrosion. One pressure vessel and one heat exchanger have been replaced in few facilities of Kuwait Oil Company during the past one year due to Hydrogen Damage and fouling. One more vessel with minor embedded defects is under inspection monitoring and engineering evaluation. Alternate remedies have been applied to minimize propagation of defects.

This paper presents field experience and application of various inspection methods in detecting embedded defects, hydrogen induced damages in the early stages, application of preventive measures to extend asset service life and asset integrity. Under this process, various advanced NDT inspection techniques were applied to detect and monitor critical internal defects on pressure vessels. Root cause analysis, fitness for service (FFS) and Risk Based Inspection (RBI) study have been conducted as a part of mitigating risks and applying remedies.
An Insightful and Robust Approach for Multi-Tool Interpretation: Moving Away from Traditional Black Box Methods
Authors: Anand Vivek , Freedman Robert , Cao Minh Chanh
Published: May 2016

In this paper a new approach for joint interpretation of petrophysical measurements acquired by multiple sensors or tools is demonstrated. This approach is based on a mapping function that can be expressed as a linear combination of radial basis functions (RBFs). The theoretical log response equations for the sensors or tools are used to compute a database covering all possible ranges of formation properties, i.e., the solution space. The database is used to construct the mapping function that relates log measurements to formation properties.

The solution space can be plotted in 2D or 3D depending on the number of input measurements. The plots provide the petrophysicist with a useful tool to:identify outliers that might denote a model inadequacy,select appropriate equation parameters that might not be obvious from individual logs, andcompute a solution consistent with the model equations.

The mapping function solutions are computationally fast, unique, and robust. In contrast, traditional multi-tool interpretations based on non-linear minimization techniques often face problems of non-uniqueness and lack of robustness.

We demonstrate the new approach using two classic examples. The first is the integration of resistivity and pulsed neutron capture logs to solve simultaneously for water saturations and salinities. This is a non-linear problem that has complex input parameter dependencies. The second example is analysis of thin-beds that have resistivity anisotropy. Even though analytical solutions exist, they are complex and it is difficult to see how, for example, net pay depends on the anisotropy. The choice of these classic examples allows us to show the simplicity of the proposed technique and to benchmark it against the traditional methods.
Advanced Reservoir and Tar Mat Evaluation Using Downhole Fluid Analysis and Asphaltene Flory-Huggins-Zuo EoS
Authors: Zuo Julian Y. , Mullins Oliver C. , Mishra Vinay , Garcia German , Zhang Dan , Dong Chengli
Published: May 2016

Advances in asphaltene science and a new generation of downhole fluid analysis (DFA) technology have been integrated to yield powerful new insights to reservoir dynamics. The Yen-Mullins model of asphaltene nanoscience has enabled development of the industry's first predictive equation of state (EOS) for asphaltene concentration gradients - the Flory-Huggins-Zuo (FHZ) EOS in oil reservoirs. The FHZ EOS along with DFA measurements has successfully addressed a variety of reservoir concerns including reservoir connectivity, viscosity gradients, and fluid disequilibrium. The model shows that asphaltene concentration gradients can be large owing to both the gravity term and gas/oil ratio (GOR) gradients. The FHZ EOS is reduced to a very simple form for low GOR black oils and heavy oils, and heavy oils are shown to exhibit enormous asphaltene concentration gradients compared to conventional black oil. In this paper, the FHZ EOS has been applied not only to calculate asphaltene concentration gradients but also to predict asphaltene phase instability in oil reservoirs and potential flow assurance issues. Two categories of tar mats are addressed, one with a large discontinuous increase in asphaltene concentration versus depth typically at the base of an oil column (corresponding to asphaltene phase transition); the second with a continuous increase in asphaltene content at the base of a mobile heavy oil column due to an exponential increase in viscosity with asphaltene content. The discontinuous type of tar mat is show to occur in two distinct setting, one more common tar mat at the base of the column and a second unusual tar mat that occurs upstructure and is permeable. The predictions are in good agreement with the laboratory and field data and the mechanisms of forming these two kinds of tar mats are also discussed. This methodology establishes a powerful new approach for conducting the analyses of asphaltene concentration grading, flow assurance and tar mat formation in oil reservoirs by integrating the Yen-Mullins model, and the FHZ EOS with DFA technology.
Harnessing Multiple Learning Styles for Training Diverse Field Personnel in Conventional Coring Operations
Authors: Lee Roger K. , Strike Patrick M. , Sutton David B. , Rengel Carlos D.
Published: May 2016

Coring is a critical operation for geologists and petrophysicists to accurately determine the amounts of hydrocarbons in a reservoir. Conventional coring is the acquisition and recovery to surface of a continuous column of reservoir formation material. This important information assists in determining the amount of oil and gas in a rock and the difficulty involved in retrieving the hydrocarbons. Coring requires use of special drillstring with inner and outer barrels. Additionally, the performance metrics for coring are vastly different from drilling. Due to its specialty nature, it is difficult to educate new and inexperienced individuals in coring operational procedures in a classroom environment.

To address the challenge, this oilfield service organization utilized a holistic approach to develop a training course for conventional coring. Content required for the course included product functionality, rig operations procedures, and troubleshooting application challenges. The key deliverable was to meet the growing learning demands from younger generations of employees. The solution was to develop a course which encompassed multi-sensory resources including auditory, visual, and kinesthetic learning. This methodology was necessary to effectively teach a wide range of topics to a diverse population of field personnel. This paper will provide details of the innovative/new learning activities that engaged the learners and facilitated their training.

Background on Coring

Conventional coring is the acquisition and recovery of a continuous column of reservoir material from depths of down to 10,000 meters to the surface with the use of purpose built coring bits and barrels. The continuous column of reservoir material, or conventional core, is captured during the creation of the wellbore when drilling through a target formation. The drilling parameters such as weight on bit, revolutions per minute, and mud flow rates, used during conventional coring typically differ compared to standard drilling. This is principally due to the primary objective of obtaining a quality intact sample of the reservoir while coring. Conventional coring has been a principle component of formation evaluation and has been around since the 1920's. As more challenging reservoirs are explored, the ability to understand and produce them has also become more difficult. However, the techniques, equipment, and personnel for coring projects have kept pace and produced increasingly more complex and diverse tools.
Best Practices and Application of Integrated Fit for Purpose Technologies to Revitalise High Water Cut Mature Fields A Case History from Offshore South China
Authors: Xiaoping Zou , Guoda Yu , Yanping Li , Yingshi Huang , Tran Thanh , Castellan Francisco , Yanping Li , Xiang Tian , Jianjun Tong , Halomoan Parlindungan Monris , Lanhua Ge , Bisain Amarjit Singh , Yang Liu
Published: May 2016

Huizhou oil field, located offshore south China, has been in production for over 20 years. Most of the primary oil was produced from 1991 to 1996 by vertical wells and commingled production. Horizontal geometric drilling was first introduced in 1997. However, as the field became more mature, the rate of success could not be sustained, and a rapid production decline began in 2000. By 2006, the field average water cut reached 90%.

A reservoir surveillance program was conducted to evaluate remaining reserves, delineate current oil water contacts, and update geologic and reservoir models. This work revealed that remaining reserves in the high-permeability reservoir accumulated in attic locations, while the reserves of low-permeability reservoirs remained unproduced despite years of commingled production with the high-permeability reservoirs.

A new horizontal drilling program was initiated in 2007 to target the 3 m to 5 m thin attic oil column of high-permeability reservoirs overlying strong aquifers. The 1 m to 3 m thin and low-permeability interbedded shale reservoirs were also targeted. Because the reservoir targets are much thinner compared to original conditions, the standoff between lateral and oil water contact is very sensitive to well performance and reserve recovery. Precise landing and lateral placement of horizontal wells and the use of inflow control devices for completion, have become critical to the success of this campaign. The results have shown 39% higher production compared to the set targets, up to 15% improvement in reserves recovery, and 14% reduction in annual field production decline rate.

Based on project results, best practices in finding and revitalizing remaining oil in mature fields and complex reservoirs were developed. Project success was also aided by applications of fit-for-purpose technologies, including advance multifunction formation evaluation and azimuthal logging-while-drilling, well placement, and inflow control devices, as an integrated solution.
Case Study: Productivity Evaluation of Ultralow-Permeability Clastic Oil Reservoir Drilled at High Overbalance with Water Based Mud
Authors: HeShen Shi , ChengGang Xian
Published: May 2016

Ultralow-permeability (1.0- to 10- md) oil reservoirs are becoming primary targets offshore China. Reliable productivity evaluation is needed for such reservoirs, which have significant technical challenges and a narrow economical margin. Evaluation of wells drilled at high overbalance with water-based mud (WBM) presents several key challenges: severe near-wellbore formation damage, lack of porosity-permeability relationships because of the complex pore structures, large-scale permeability effects from pronounced heterogeneities, and big discrepancies among the permeability sources for which analysis is complicated by different measurement environments and interpretation methods. Parameter discrepancy creates significant bias for determining cut-offs and optimizing completion and stimulation strategies. More significantly, defining producible pay and consequently how it will produce are greatly complicated by capillary pressure and relative permeability conditions. Very different pictures may be drawn if these challenges are not addressed systematically.

A comprehensive case study provided lessons learned for the productivity evaluation of an ultralow-permeability clastic oil reservoir drilled at high overbalance with WBM. An integrated approach was conducted to overcome challenges by using all available data through extensive data acquisition. Flow-based rock typing (FBRT) with a neural network used pore structure, capillary pressure, and relative permeability as key inputs or control parameters in addition to the routine parameters in conventional rock-typing methods. Different permeability sources with different scales were systematically integrated and up-scaled into a numerical model based on classified FBRTs and validated by history matching of dynamical tests. Pore structure delineation is identified as the key input for reliable productivity evaluation. FBRT presents an attractive solution if measurements of pore structure, capillary pressure, and relative permeability and dynamical data are carefully used. Optimizing productivity must start with minimizing formation damage and progress through optimizing completion and stimulation.
The Spectrum of Fine-Grained Reservoirs From
Authors: Bohacs K.M. , Passey Q.R. , Rudnicki M. , Esch W.L. , Lazar O.R.
Published: May 2016

A spectrum of combinations of rock and hydrocarbon properties in fine-grained rocks can result in significant production, effectively spanning 'conventional' tight oil to fractured 'shale' gas reservoirs, in four main families based on dominant porosity-permeability system and stratal relations (i.e., 'Conventional' tight, Hybrid/Interbedded, Porous 'shale', Fractured 'shale'). Fine-grained reservoir types comprise 'shale-oil' reservoirs at lower thermal maturities and pressure-temperature (P-T) conditions to 'shale-gas' reservoirs at higher maturities and P-T conditions. These fine-grained reservoirs can contain a variety of pore types: inter-granular, intra-granular, fracture, intra-kerogen, and intra-pyrobitumen/char -- the last two 'organic-hosted' types are more obvious at higher maturities.

'Shale-oil' reservoirs share many attributes with 'shale-gas' reservoirs, but have some distinct differences. The key additional dimension is the properties of the hydrocarbon fluids: Over geological time, fluid density and phase influence fluid saturation in the matrix, and in the short term, viscosity and phase affect flow and production rates. Hence, two main classes of attributes affect ultimate 'shale' reservoir performance: rock properties (mainly permeability) and fluid properties (mainly viscosity) that are influenced by the full geological history of the reservoir. Overall reservoir permeability includes both matrix and fracture characteristics: Matrix permeability is a function of original depositional composition, texture, bedding, and stratal stacking plus burial history (thermal stress, diagenesis). Fracture permeability is a function of the same controls as matrix permeability along with structural history (mechanical stress). Fluid properties (viscosity, density) are also controlled by original depositional properties (which determine kerogen type) and burial/uplift history, along with present-day reservoir pressure and temperature.

The higher thermal maturities of 'shale-gas' reservoirs result in contrasts with 'shale-oil' reservoirs: they tend to have less smectite due to illitization, but more obvious porosity associated with kerogen and bitumen. These factors modify the porosity-permeability system and well-log responses. Appreciation of the similarities and differences between 'shale-gas' and 'shale-oil' enables more efficient and effective exploitation of the full range of resource types.
The Adaptability Research of Steam Flooding Assisted by Nitrogen Foam in Henan Oilfield
Authors: Lu C. , Liu H.Q. , Lu K.Q. , Liu Y.G. , Dong X.H.
Published: May 2016

With the further study on foaming agent performance, steam flooding assisted by nitrogen foam has been applied more widely. But the flexibility of this technology in heterogeneous shallow layer heavy oil reservoir has not been fully researched.

Through introducing a new dimensionless parameter—foam comprehensive evaluation index (FCEI), we use physical simulation to evaluate foaming agents. Then we make five sand filling tubes modeling permeability contrast in the light of Henan heterogeneous shallow layer heavy oil reservoir. Based on two kinds of foam-injected methods (steam following or not) impact analyses, the applicability of foam to multi-permeability contrast is further discussed. Furthermore, we use numerical simulation to optimize parameters including foam slug size, nitrogen steam ratio, foam injection interval and production-injection ratio, which applied to this type of reservoir.

The obtained results show that through foaming coefficient and decay coefficient, FCEI can unify the criteria of foam screening by taking foam volume and half-life into consideration. On even ground, compared with cold foam flooding, the oil production of unit foaming agent of hot foam flooding stays 1.24 % higher. There exists none negative correlation between foam's contributions to each layer's flooding efficiency and permeability. Two methods both indicate that the middle permeability layer, of which the producing degree is similar with lower ones, has great exploitation potential. When injected with cold foam, the start-up pressure of heterogeneous formations increases linearly along with the increase of permeability grade, but for hot foam, this value increases in function of power. And to higher permeability contrast layers, hot foam is better. Finally, under hot foam slug injection condition, the optimum foam slug size is 0.02PV, the optimum nitrogen steam ratio is 20:1, the optimum foam injection interval is 90 days and the best production injection ratio is 1.32:1.

Based on the study, this technology has been applied for selected field sites in 2011, and preliminary results have been achieved. The results demonstrate that this research can play an important guiding role in applying steam flooding assisted by nitrogen foam to heterogeneous shallow layer heavy oil reservoir.
Successful Multistage Hydraulic Fracturing in V-Shape Well as a Method for the Development of Coal Bed Methane in China
Authors: Qu H. , Jiang T. , Liu Y. , Wu Z. , Xie X. , Chi S.
Published: May 2016

There is a rich coal bed methane reserve in the southeast margin of ordos basin. Hydraulic fracturing stimulation is the primary completion method to coal bed methane wellbores for many years in this area. Recently, V-Shape wells, which are complex architecture wells composed of a vertical well and two horizontal wells, are in order to improve recovery of CBM. Two horizontal wells intersect with vertical well in same depth, and the included angle between two well tracks of the plan projection is about 44 degree. Multistage hydraulic fracturing technology was treated two horizontal wells to create fracture network and induce nature fractures. Then, the vertical well was used to drainage to decrease bottom pressure.

Based on the geologic parameters, a total of eight stages were placed on two horizontal sections. One had three fractures, the other had five fractures. According to wellbore condition, pump bridge plug technology was used to execute multistage fracturing treatments. During field operation, 7200 m3 active water was mixed with quartz sand (492m3) and pumped down two wells together. The averaged proppant concentration was 14%. Because of included angle, the number of sand changed with stage increasing to avoid interference among fractures within two wells. And in the final stage, the treatment deployed 100m3 sand, and proppant loading reached to about 41750 Kg/m of net coal. This created a new Chinese record of proppant loading in coal bed methane.

Consequently, the first V-Shap well group was successfully treated in china. This work can research the application of special technology well in CBM, evaluate the effect of multi stimulation treatments, and confirm the gas content. It also provides the reliable guidance for the reasonable development of CBM reserve in the future.
Improved Oil Recovery by Hydrophilic Silica Nanoparticles Suspension: 2-Phase Flow Experimental Studies
Authors: Li Shidong , Hendraningrat Luky , Torsaeter Ole
Published: May 2016

In last decade, a number of papers about nanoparticles studies have been published related to its benefit for oil and gas industries. Some of them discussed about the potential of nanoparticles for enhanced oil recovery (EOR) in the laboratory scale. One of possible EOR mechanisms of nanofluids has been described as disjoining pressure gradient (Chengara, 2004, and Wasan, 2011). The benefit of using silica nanoparticles was explained by Miranda (2012). Hence, the present study objective is to investigate the potential of hydrophilic silica nanoparticles suspension as enhanced oil recovery agent and find out the main mechanisms of nanofluids for EOR.

In this study, hydrophilic nanoparticles with average particle size of 7 nm were used in both visualization glass micromodel flooding experiments and core flooding experiments. A water-wet transparent glass micromodel and Berea sandstone cores with 300–400 mD permeability were used as porous medium. Synthetic brine was used as disperse fluid for nanoparticles. In order to investigate the recovery mechanisms of nanofluids, interfacial tension (IFT) and contact angle between different concentration nanofluids and crude oil have been measured by using spinning drop and pendent drop methods.

The experimental results indicate that the nanofluids can reduce the IFT between water phase and oil phase and make the solid surface more water wet. In the visualization glass micromodel flooding experiments, it was observed that nanofluids can release oil drops trapped by capillary pressure, while the high concentration nanofluids stabilized oil-water emulsion. For the core flooding experiments, nanofluids can increase recovery about 4–5% compared to brine flooding. These results indicate that these nanoparticles are potential EOR agents. The future expectation is that nanoparticles could mobilize more oil in the pore network at field scale to improve oil recovery.
Combining Asphaltene Science and Downhole Fluid Analysis for Improved Reservoir Characterisation
Authors: Elshahawi Hani , Dong Chengli , Latifzai Ahmad , Zuo Julian , Mullins Oliver C.
Published: May 2016

Understanding reservoir complexities such as compartmentalisation and compositional gradients early in the life of a field is crucial for its optimal development. That's especially true for deepwater reservoirs. Deepwater exploration and development has become a key area for most E&P companies because of the increased global demand for oil and gas and the limited accessibility of other potential unexploited resources. Modern wireline formation testers can provide a wide range of downhole rock and fluid properties at in-situ reservoir conditions and can help diagnose deepwater reservoir issues such as compartmentalisation and compositional grading early on. Advanced downhole fluid analysis (DFA) performed by wireline formation testing tools provides real time quantitative measurement of variation in asphaltene content as manifested though fluorescence and fluid coloration. Gas-oil ratio (GOR), another key determinant in asphaltene stability and gradients, is also measured downhole with the DFA technique. Building on recent advances in asphaltene molecular and colloidal physics, a new asphaltene equation of state (EoS) can be used to model asphaltene gradients in crude oils in the same way that a traditional cubic EoS is used for modeling GOR gradients.

In this paper, we analyze a deepwater case study showing increases in asphaltenes content with depth due to destabilisation resulting from secondary gas charging at the top of the column and with solid hydrocarbon/tar depositing at the base. These seemingly contradictory observations are shown to follow from a new nanoscience model of asphaltenes. A simple model is proposed for this tar mat formation and consisting of disequilibrium gas charging, large disequilibrium gradients of asphaltene and GOR, asphaltene instability in the oil, and tar in the core. Likely compartmentalisation will also be identified using DFA analysis and verified using lab data analysis, allowing integration into the reservoir modeling process.
How to Get the Most Out of Your Oil Rim Reservoirs?
Authors: Masoudi Rahim , Karkooti Hooman , Othman Mohamad B.
Published: May 2016

Oil production from oil rim reservoirs has always been a challenge due to their thinly spread oil resources and complicated production mechanisms. Movement of oil/water and gas/oil contacts could be very sensitive to conventional production operation and cause detrimental early water/gas breakthrough. The low oil production volume and hence low recovery (typically less than 18%) make the oil rim field development economically less attractive. However, integration of state-of-the-art engineering approaches, innovative technical initiatives and new technologies can make a significant change in the oil rim reservoir development.

This paper, which is a brief of the author's recent SPE distinguished lecture on the same topic, disseminates the applied fundamentals, critical elements and proven practices to maximize the hydrocarbon recovery in successful and integrated oil rim developments. The paper covers the reliable volumetric assessment and development concept (i.e., sequential, concurrent, etc.), robust and proactive reservoir management/monitoring policy to advice on depletion strategies and production to control the conning and cusping of water and gas. In addition, utilizing new technologies, appropriate production technology advice to assist timely development decision making, best simulation and modeling approach for the applied technologies (e.g., Horizontal/Multilateral wells, smart wells/completion, ICD/ICV, tracer, etc.) and complicated mechanism and dynamics involved in oil rim development are explained and discussed.

The recommended workflow, guideline and technical initiatives will be elaborated throughout the paper and the success and value creation of the recommended methodology will be demonstrated in various real case studies. The paper demonstrates progressive and step-by-step recovery factor improvement up to additional 20% in the studied real cases.
Advanced Methods for Internal Multiple Attenuation
Authors: Hung Barry , Wang Min
Published: May 2016

Internal multiple attenuation (IMA) has long been regarded as a challenging problem in seismic data processing. The major difficulty stems from the need of identifying the multiple-generating interfaces for IMA. We present and compare two advanced IMA methods that a-priori knowledge about the multiple-generating interfaces is not required in the modeling process. The two approaches are inverse scattering series (ISS) and our methodology based on the convolution-correlation process. We describe our implementation procedure that involves segmenting the input data into different time windows and using a sliding-window approach to ensure that all the top multiple-generating interfaces are included in the modeling process so that internal multiples of all orders can be predicted without any subsurface information. We also discuss and compare the different assumptions made in ISS and our approach for IMA. We show the application of the two methods for handling internal multiples on both the synthetic and field data from the Tupi oilfield in the Santos Basin and on the field data acquired offshore Australia.
An Application of Depth Imaging to Support the Appraisal Phase of a Reservoir Affected by Poor Signal to Noise Ratio
Authors: Ciaccio T. , Andreoletti C. , Fichera R. , Biancone M. , Ellis G.
Published: May 2016

In this paper a workflow that integrates the most advanced tools for seismic data processing and imaging to overcome limits imposed by poor seismic data in the definition of reservoir geometries with the details needed to properly locate the appraisal wells is presented.

The area of study is the north-western coast of Australia. Here the reservoir, Middle Jurassic sandstones, is affected by a very poor signal to noise ratio due to poor energy penetration and illumination associated with reefs, faults and a high level of multiples content that completely masks the target area.

In the following, we will describe our approach to depth imaging with robust velocity analysis, effective attenuation of multiples, choise of most suitable migration algorithm and constant interaction between geological and geophysical expertise. The application of this integrated approach was the added value of the project and the main driver for guiding the interpretation of the reservoir, providing a strong support for well planning.
Design and Application of Expandable Casing Drilling Technology of Deep Sidetrack Horizontal Well in Tahe Oilfield
Authors: Ming Tang
Published: May 2016

The deep sidetrack wells of Tahe oilfield require to meet requirements of avoiding water, and drill to the leakage zone and collapse area of carboniferous system, two pressure systems need to be drilled, which traditional drilling fluids and chemical plugging method can't ensure drilling safety, and if running the conventional casing into the hole, drilling and completion face many difficulties because of following slim hole. All above making the old deeply areas remaining oil can't be liberated.

Expandable casing technology is a new technology, which acts as intermediate casing to block complex formation during drilling. It can optimize the structure of the well bore, block abnormal high pressure layer, collapsed layer and leaking layer, providing a technical plan to drill successfully to the target for complex deep wells.

According to the developing difficulties of F177.8mm casing deep sidetrack horizontal wells in Tahe oilfield, it produces a solution of expandable casing, analysis the operating difficulties of expandable casing, proposes an expandable casing technology solution, adopts unconventional diameter 130mm borehole drilling after expanded. It also describes in detail the drilling block application of expandable casing technology for the first time in the sidetrack horizontal well.

Field application shows that expandable casing drilling technology program designed can solve the drilling problem of the deep sidetrack horizontal well of the Tahe oilfield, and gains good technical practice. The effect of application confirms that the expandable casing implementation can meet the drilling block and follow unconventional slim hole drilling requirements.

In conclusion, the expandable casing drilling technology is the first time for technical casing of sidetrack horizontal wells, which proves the practicability of expandable casing drilling solution, and provides a new way to solve the development problems in Tahe oilfield. Meanwhile we successfully solves the unconventional diameter 130mm borehole drilling problem, using the non-standard small-diameter MWD instrument and non-standard diameter 89mm drill pipes for the first time, perfects slim hole drilling process. Furthermore, this application successfully provides the technical foundation of expandable casing technology in complex stratigraphic drilling.
Enhancing Static Interpretations Using Histogram Equalisation and Edge Detection
Authors: Al Ghamdi Ahmed , Al Garni Khalid
Published: May 2016

In this paper, we introduce a workflow to improve stratigraphic and lithologic interpretations by improving static analyses of seismic data using a histogram equalization technique. In particular, we demonstrate the use of histogram equalization followed by edge detection to enhance geological features such as faults, fractures, and channels. Post-stack and migrated seismic data are often subjected to automatic gain control (AGC) to increase the visibility of low-strength reflections. Unfortunately, AGC can mask stratigraphic details by drastically changing relative amplitude levels and by producing low-amplitude "shadow zones" near strong reflectors and near unconformity terminations.

Histogram equalization (HE) was originally developed for image processing but serves a useful purpose for seismic analysis. Unlike AGC, histogram equalization preserves subtle stratigraphic features and does not create "shadow-zones" beneath strong reflectors. Histogram equalization enhances the sharpness of stratigraphic features, thereby allowing edge detection algorithms to more effectively highlight discontinuities in the amplitude level even if the change is small.
Cold Lake Commercialization of the Liquid Addition to Steam for Enhancing Recovery (LASER) Process
Authors: Stark Shane D.
Published: May 2016

The Cold Lake project, in Alberta, Canada, is one of the world's largest heavy oil in-situ thermal developments with oil production of about 24,000 m3/d (150 kB/d) from more than 4000 wells. The world class Cold Lake hydrocarbon resource is a bitumen deposit, featuring in-situ viscosities in excess of 100,000 cP. The high viscosity of Cold Lake bitumen severely limits steam injectivity below fracture pressure, necessitating the development throughout the 1970s and 1980s of a modified cyclic steam stimulation (CSS) recovery process.

Imperial Oil and ExxonMobil are pursuing a research program to develop the next-generation of bitumen recovery processes that use hydrocarbon solvents as a mobilizing agent, reducing greenhouse gas (GHG) emissions relative to the current commercial recovery processes. Imperial and ExxonMobil are pursuing three processes: a solvent-only process known as Cyclic Solvent Process (CSP), a solvent assisted SAGD process and a solvent assisted CSS process known as Liquid Addition to Steam for Enhancing Recovery (LASER). LASER has the potential to increase oil recovery by more than 5% and reduce direct GHG emissions intensity by approximately 25%.

This paper describes the first commercial application of LASER. The Cold Lake H trunk LASER project is to date the world's largest implementation of a thermal solvent recovery process, with injection of 297 km3 (1.87 million barrels) of solvent into the 240 well project. This paper describes the successful operation of this thermal solvent project over a six year period; including reservoir numerical simulation work to develop bitumen and solvent production forecasts, development of field solvent production measurement methods, and the recovery process learnings from the first cycle of LASER operations. Completion of the first commercial LASER cycle has demonstrated on a large scale the success of solvent addition as a means to increase thermal efficiency and oil production in a heavy oil thermal recovery operation.