bluuebunny/crossref_metadata_2025 huggingface dataset:
System Monitoring And Controlling Water Nutrition aquaponics Using Arduino Uno Based Web Server
Authors: Maarif Amanda Fahmi
Published: November 2016

Aquaponics is a sustainable farming system that combines aquaculture and hydroponics systems as an integrated system that is symbiotic. In an aquaponics system results from animal excretion contained in this system will be used as natural nutrients hydroponic plants. As for the animals that live on this system will also result in clean water that has been filtered naturally by the plant roots. In the cultivation of an aquaponics system an important factor affecting the development of the ecosystem is the degree of acidity (PH) which have a direct impact on the absorption of nutrients in the roots of plants and development of animals that live in this ecosystem. In addition, factors that are not less important is the electroconductivity (EC) is the ability to conduct an electric ion in solution to the plant roots. The degree of acidity (pH) of water that is normal for an aquaponics ecosystem at 6-7 and value for EC ranged in value of 0.8-1.2 ms / cm. From this study produced a tool that is capable of monitoring in the form of a web server and conduct automatic action in controlling the levels of PH and EC. Based on the results of system testing results obtained sensor Analog PH Meter Kit and Analog Electrical Conductivity Meter capable of monitoring water tank in accordance with the standard measurement tool used is PH meter and EC Solution and the system is also able to control the changes that occur in the water tank in accordance with the standards of PH and EC. Keywords: Aquaponics, Arduino Uno, PH, EC.
Dynamic Flow Simulation to Study Flow Assurance Challenges in Water Alternating Gas WAG Wells
Authors: Karimi Hassan , Putra Erni Dharma , Thakur Kapil Kumar , Yusuf Rahel , Shaharun Azwan , Hallquist Aron E.
Published: November 2016

Water-alternating-gas (WAG) is an enhanced oil recovery process which is being widely practiced in the oil fields to increase the extent of the reservoir contacted by the displacing fluids, the gas is generally injected intermittently with water. WAG process improves the recovery from the reservoir and hence increases the production performance; however, the process of alternating water with gas, if not properly studied and designed, would lead to several flow assurance issues including hydrate formation risk, unsuccessful fluid displacement, bottom hole pressure exceeding fracture pressure and vacuum/low pressure condition at the surface etc. All these factors can impact the success of the WAG operation.

Dynamic modelling of the water alternative gas changeover process is essential to address the potential challenges during changeover operation and also to formulate the operational guidelines. Each type of changeover (i.e. water to gas / gas to water) have unique challenges which is discussed in detail in this paper.

This paper presents the results of the modelling and simulations of WAG operation carried out on a horizontal well. Of particular interest is the the period of change over interval (i.e. gas to water and water to gas) where there are significant pressure, flow and temperature transients leading to possibility of various flow assurance related risks. These risks were evaluated in detail for the subject well and the WAG changeover operation was designed to avoid any potential problems using transient multiphase flow simulation.
Injectivity Improvement by Nanofluid Preflush During Low Salinity Water Flooding
Authors: Yuan Bin , Wang Kai
Published: November 2016

This paper evaluates nanoparticle utilization to mitigate the injectivity loss due to pore-throat blockage near the wellbore. We develop a theory to explain how nanoparticles control particulates migration in the formation, and thus improve injectivity. Nanoparticles are pre-coated on the rock grains in 1-D porous medium prior to the injection of newly fine particles during low salinity water flooding. We hypothesize that the positive contribution of nanoparticles is related to the increased maximum retention capacity of the host rock by reduction of the surface potential between rock grains and suspended particulates. We develop semi-analytic MOC (method of characreristic) solutions for two different reference scenarios, in view of the difference between the initial attached fines concentration and the initial maximum retention concentration of fines without nanoparticle effects.

The effluent history plots are compared with the experimental data to verify the proposed theory. In addition, suspended, attached, and strained particle concentration profiles are calculated to evaluate the particle transport in a one-dimensional model. Our solution suggests two weak-form discontinuity fronts moving along the porous medium: suspended particle and attached particle fronts. The solution explains how effectively nanoparticles can prevent the decreased permeability through fixation of mobile particles. Permeability impairment and an associated increase in injection pressure (assuming a constant injection rate) are studied via mitigation index (MI) and injection index (J).

Through quantitative comparison of effluent concentration history and permeability decline, we validate the accuracy of the predictions. In practice, this paper provides analytical approach to evaluate performance of nanoparticles pre-treatment to sustain injection rate during low salinity water flooding.
Analytical Solution of Matrix Permeability of Organic-Rich Shale
Authors: Wang Rui , Zhang Kai , Detpunyawat Pachari , Cao Jiayi , Zhan Jie
Published: November 2016

Apparent matrix permeability of organic-rich shale is complicated because of its unique pore structure, gas storage and transport mechanisms. In inorganic pores, free gas is the only phase considered. While in organic pores, adsorbed phase coexists with free gas. Surface diffusion is the transport mechanism of the adsorbed phase. However, transport mechanism of free gas varies during production and is distinguished by the Knudsen number. Slip flow, transition flow, Knudsen diffusion and surface diffusion are found in organic pores, whereas only slip flow and transition flow occur in inorganic pores. The effects of pore size, pressure and temperature on the transport mechanism are discussed. Pressure reduction causes a change in transport mechanisms during production. Stress dependency of inorganic pores is one of the factors that affect pore size, transport mechanism and permeability. The apparent permeability is derived by calculating the geometric average of permeability of different units with varying pore sizes and permeabilities. Sensitivity analysis shows that stress-dependency plays an important role in inorganic pores, which results in the positive correlation between permeability and pressure. Conversely, in inorganic pores, permeability increases as pressure decreases. As a result, permeability decreases and then increases with decreasing pressure.
The Gaussian Process Regression for TOC Estimation Using Wireline Logs in Shale Gas Reservoirs
Authors: Yu Hongyan , Wang Zhenliang , Rezaee Reza , Zhang Yihuai , Xiao Liang , Luo Xiaorong , Wang Xiangzeng , Zhang Lixia
Published: November 2016

Total organic carbon (TOC) estimation is very important for shale gas reservoir characterization. There are many introduced methods for TOC prediction in organic-rich shales. However, there are still some weaknesses with the most of the methods. This paper proposes a new method using machine learning, Gaussian Process Regression, which is expert in processing high-dimension, small samples, and non-linear problems. Compare to the Neural Network, and Support Vector Machine, Gaussian Process Regression has adaptation and generalization ability. This paper takes Zhangjiatan shale of the Yanchang Formation of the Triassic period in the south-eastern Ordos Basin as an example. A total of 7 kernel functions are applied to build the regression model. As a result, the Cauchy kernel is chosen due to lowest error. Then, feature selection is carried on based on the weights which calculated from 4 weights algorithms. Finally, compared the Gaussian Process Regression results to the traditional methods, (e.g., Passey and Schmoker methods), we found that Gaussian Process Regression works well for TOC estimation.
3D True-Amplitude Anisotopic Beam Depth Migration of 3D Irregular Data
Authors: Protasov M. , Tcheverda V. , Isakov N. , Pravduhin A.
Published: November 2016

The paper addresses 3D seismic depth true-amplitude migration of 3D irregular data in anisotropic media based on beam decomposition of the data. The main objective is the development of the imaging procedure suitable for anisotropic media and handling 3D irregular seismic data without any preliminary regularization. The real data examples from Eastern Siberia are presented and discussed.
Enhancing Seismic Imaging of Deep Structures Using Anelliptic VTI Traveltimes
Authors: Alashloo S. Y. Moussavi , Ghosh D. P. , Shahbazi A. , Hermana M. , Ismail W. Y. Wan
Published: November 2016

The presence of sedimentary layers in the Earth's subsurface results in seismic anisotropy, which makes wave velocity dependent on the propagation angle. This aspect causes errors in seismic imaging such as mispositioning of migrated events if anisotropy is not accounted for. One of the challenging issues in seismic imaging is the estimation of anisotropy parameters which usually has error due to dependency to several elements such as sparse data acquisition, erroneous data with low signal to noise ratio, etc. In this study, an isotropic and anelliptic VTI fast marching eikonal solvers are employed to obtain seismic traveltimes required for Kirchhoff depth migration algorithm. Computing cost of fast marching method is O(NlogN) which is faster than the general finite difference methods with cost of O(N2). The Sigsbee synthetic data and a real dataset are used for testing purposes. The comparison of isotropic and VTI traveltimes demonstrates a considerable lateral difference among wavefronts. The results of Kirchhoff imaging show that the VTI algorithm generates images with perfect positioning and higher resolution than the isotropic one, specifically in deep areas. Finally, we conclude that our anisotropic approach is stable, fast, and generates high-quality images with accurate details in deep structures.
Lateral Vibration Analysis of Oil Production Casing String in Deepwater Shallow Under Earthquake Excitations
Authors: Song Deng , Honghai Fan , Yuhan Liu , Jing Yang , Zixiang Wen , Deqiang Tian
Published: November 2016

The majority of deep-sea oil and gas exploration areas are located in seismic active zone, such as the South China Sea and Suez basin in Egypt. As casing string vibration caused by earthquake and low deep shallow soil cementation strength may result in the instability of deep water flow string, moreover, the pipe string failure may bring about economic loss and environmental damage. In this paper, lateral stability analysis of pipe in deep water shallow is taken into consideration for seismic analysis, and the string is considered as a Winkler model. First, it carries out stress analysis of flow string, and lateral stress includes wave load in wellhead, transverse moment imposed by bottom casing, ground resisting force and seismic force. Dynamic differential equation of string in deep water shallow is established on the basis of soil dynamics and pipe-string mechanics. Displacement attenuates and bending moment distribution of the string are calculated in three different seismic data, therefore the conclusion can be obtained as below: The string displacement amplitude increases as the intensity of earthquakes increases, and the biggest bending moment lies in the casing cross section, which is the point that may be easily damaged if the earthquake happens. In this paper, analysis of the transverse vibration of the shallow casing string wil help us better understand the casing string vibration in deepwater oil and gas exploitation and transportation so as to reduce the occurrence of the accident. Finally, some suggestions are given below, such as RMR \ MPD drilling technology, Open Hole Interval and structure of wellhead support device to enhance the stability of production string, ensure well integrity and reduce accident loss.
Quantification of the Tetraprotic Acids Content in Oils for the Prediction of Naphthenate Deposits Risks
Authors: Molinier V. , Loriau M. , Lescoulié S. , Martin B. , Gingras J. P. , Passade-Boupat N.
Published: November 2016

During oil production and transport, several deposit risks may arise due to varying physical conditions (Pression, Temperature) and chemical nature of oil and water (salinity, pH…). These deposits are mainly hydrates, waxes, asphaltenes, inorganic or organic salts, and their occurrence must be avoided in order to ensure a proper flow assurance during oil production. Particularly, precipitation of calcium naphthenates can occur in the presence of divalent cations (calcium) in basic pH conditions and can lead to dramatic clogging of installations. Compared to some of the other deposits, this one is particularly difficult to predict because it depends on the presence of trace levels of specific species in the crude oil.

A decade ago, a particular family of naphthenic acids, called "Arn" or "Tetraprotic Acid" (TPA), has been identified in naphthenate deposits.[7] The occurrence of these acids has been shown to be closely related to naphthenate deposit risks: the tetraprotic nature of these acids favors the formation of polymeric-like calcium precipitates able to imprison oil and solids, leading to impressive deposits. Since then, analytical efforts have been made to quantify the presence of Arn in crude oil, in order to mitigate calcium naphthenate deposits thanks to predictions tools based on chemical equilibriums.

In this work, we have put to the test a method of Arn quantification described in the literature, based on SPE (Solid Phase Extraction) and HPLC-UV quantification. A selection of crude oils of varying origin and chemical nature (Total acid content TAN, Total base content TBN, Asphaltenes content) has been chosen to enlighten the effect of oil on the Arn extraction yield. Particularly, we have shown that for crude oils with high TBN values, two consecutive SPE extraction steps are necessary to ensure proper extraction. We have also shown that the optimization of the SPE extraction steps (amount of oil, cartridge capacity, elution volumes) is crucial for proper Arn quantification. Finally, Arn extraction yield is shown to depend on the oil nature and therefore a quantification of spiked samples is necessary.

This work gives some guides for proper quantification of the tetraprotic acids content in crude oil in order to get a reliable concentration value that can be further used to predict naphthenate deposit risks.
Integrated Sonic Shear Compressional Ratio for Seismic Rock Physics Calibration in the Development Gas Field a Case Study in Tapi Field of North Malay Basin
Authors: Fadjarijanto A. , Pakpahan O. , Kaewtapan J. , Setiawan A. S. , Simatupang M. H. , Rahmadi A.
Published: November 2016

This paper presents a novel approach by integrating well log data evaluation to seismic rock physic calibration of field development plans. The result of the study was incorporated in the development drilling to optimizing well placement. To date, the well result demonstrates that the method was proven to determine the gas bearing sand distribution. As a consequence, drilling at a sweet spot location can be optimized.

Reservoir fluid identification is a major role in the formation evaluation task. In the field with multiple stack sands and limited water salinity data, will cause more challenging to define fluid type. The result is very substantial to determine hydrocarbon in place, the volume of which will be used to take the decision to develop the gas field. The inherent uncertainty which comprises of sand and hydrocarbon distribution is a real challenge when identifying the sweet spot location in a development drilling campaign.

Well log data provides essential information that will use for interpretation of lithofacies and fluid type. The elastic acoustic velocity of the formation taken by sonic tool is a common data that are considered in the petropysical evaluation. In essence, the advantage of ratio of sonic compressional to shear wave velocity is applied to identify gas bearing formations. This is based on the fact that compression wave is more sensitive to type of fluids than the shear wave when it travels into the poro-elastic formations. The same method is also relevant when applied to the seismic data. The seismic Vp/Vs ratio must be first calibrated with well data to provide a proper meaning. Thereafter, the seismic Vp/Vs ratio is exerted to determine gas bearing sand distribution. This information is expected to deliver a great contribution in the well placement optimization.

The method is proven to reduce the uncertainty of lateral distribution at shallow reservoirs. The application of this method for deeper reservoir is still being investigated and further detail works will be done to confirm the findings.
Cost-Effective Removal of Hydrogen Sulfide from Oilfield Mixed-Production Systems
Authors: Lehrer S. , Ramachandran S. , Soos L. , Leidensdorf J.
Published: November 2016

The production of sour crude oil results in the release of hydrogen sulfide (H2S) into surface equipment causing compliance, safety, environmental, and corrosion concerns for the producer. Increased costs result with high hydrogen sulfide concentrations due to pipeline contract penalties, the need for additional gas sweetening equipment (i.e., towers), increased manpower costs for monitoring, metallurgical upgrades, and liability from the potential release of H2S. These issues can be alleviated if H2S is reliably removed in a cost-effective manner by direct injection of H2S scavengers into mixed-production systems.

Variability in production flowrates and H2S levels from factors such as well slugging results in an inconsistent amount of H2S that must be removed. Additionally, in many cases there are very short residence times available for scavengers to function. Achieving consistent and cost-effective removal of H2S from mixed production is very difficult. Conventional H2S scavengers, including triazines as well as non-nitrogen scavengers, have been used successfully to remove hydrogen sulfide from separated oil and gas. However, these scavengers exhibit slow kinetics and low thermal stability for mixed-production applications. As a result, poor efficiency is observed in many of these applications. In the case of triazines, their high scaling tendencies are also a concern. To address the kinetic and thermal stability limitations of existing scavengers, new scavengers were developed to achieve reliable removal of H2S from mixed production. Advantages of these new scavengers include higher thermal stability, faster kinetics and efficient H2S removal, resulting in consistent performance under varying conditions.

Field test results will be presented for mixed-production applications, demonstrating the ability of these new scavengers to reliably remove H2S. These new scavengers are effective over a broad temperature range and are suitable for topsides and downhole injection.
Penetration Performance of a Shaped Charge Perforator in Sandstone and Limestone Targets at Extreme Pore Pressures and Constant Effective Stress
Authors: Haggerty D. , McGregor J. , Barker J. , Manning D. , DeHart R.
Published: November 2016

As the oil and gas industry expands perforating operations into higher-pressure environments, it becomes necessary to understand the effects of these higher pressures on the penetration capability of shaped charge jets. This paper discusses an investigation wherein penetration effects of shaped charge perforators were studied in both sandstone and limestone at ultrahigh pore pressures up to 32,000 psi under constant 10,000 psi effective stress in a laboratory environment. Sandstone and limestone cores were configured into targets guided by API RP 19B Section 2 methodology (2006). A specific shaped charge was selected to shoot in these targets with the only variable being the pressure conditions of the tests. These configurations consisted of oil-saturated cores with pore pressures ranging from 2,000 to 32,000 psi under a constant effective stress of 10,000 psi. High-resolution computed tomography (CT) scan images were not only used to measure an accurate penetration depth and perforation tunnel dimensions, but also to provide a 3D view of the resulting perforation tunnel for qualitative analysis. Penetration depths were obtained as a function of pore pressure up to 32,000 psi in both sandstone and limestone rock types at a constant effective stress of 10,000 psi. The results showed that jet penetration continued to decrease even though the effective stress was held constant, from a higher rate of decline between 2,000 and approximately 14,000 psi to a lesser rate of decline between 14,000 and 32,000 psi. Interestingly, the higher unconfined compressive strength (UCS) limestone exhibited slightly deeper penetration than the lower UCS sandstone above a threshold pressure. Visual observations included the location of open zones along the length of the tunnel. The effects of increasing the pore pressure on resulting tunnel geometry were revealed in the high-resolution CT images. The increasingly robust surge, known as dynamic underbalance (DUB), was elevated at each higher pressure, resulting in different perforation tunnel geometries. Further, the limestone generally showed a less disturbed tunnel than the sandstone at the higher pore pressure tests.

This range of pore pressure conditions have never been reached in an API RP 19B Section 2-type test previously. The penetration results should be useful as a predictor of perforator performance whenever higher reservoir pressure well environments are encountered.
Mangala Field Tracer Data Acquisition and Residence Time Distribution Analysis: Results on the Pattern Water Flood and EOR Pilot Area
Authors: Raj Rahul , Verma Sumil , Kumar Pankaj , Kumar Sanjay , Pandey Amitabh
Published: November 2016

The Mangala field in the Rajasthan state of western India was the first major oil discovery in Barmer Basin. The heterogeneous upper Fatehgarh (FM-1 and FM-2 sand) is developed with pattern water flooding. The well fluid are produced through Jet Pump (artificial lift) and processed in a plant (Mangala Processing Terminal, MPT). The separated produced water is mixed with Thumbli aquifer water for injection and as power fluid water for Jet Pump. The injection water is heated above reservoir temperature as to prevent any insitu wax deposition.

To qualify the support of injector for its pattern producers in heterogeneous multi stacked FM-1 sand, conservative tracers were strategically injected in three crestal patterns of FM-1. The paper discusses the results of inter well tracer test conducted in FM-1 sand of Mangala. The paper focuses on the Residence Time Distribution Analysis of Tracer output signal. To meet the actual field condition of tracer reinjection via processed produced water and tracer addition via powerfluid water circulation, some modification in theoretical assumptions of Residence Time Distribution (RTD) analysis are also suggested. The RTD technique is used to estimate the sweep efficiency/ swept pore volume, and to estimate Lorentz coefficient (Lc). The estimated Lc from tracer analysis matches with the Lc being used in the simulation models.

For assessment of EOR potential in Fatehgarh formation, chemical EOR pilot consisting of four injectors and single central producer was conducted in FM-1. Tracers were added in water/polymer/ASP phases of the pilot. The paper compares the sweep efficiency/swept pore volume in three phases of water/polymer/ASP injection with the help of RTD analysis. Better sweep efficiency and more swept volume are observed in polymer phase injection in comparison to the water flooding phase.

The paper also focuses on use of qualitative signature of Tracer output for Reservoir Management and Production Optimization.
Low Resistivity Pay Evaluation, Case Study: Thin Bed Sand-Shale Lamination Reservoirs, Peninsula, Malay Basin
Authors: Amelio Tolioe William , B Mat Ismail M Shah , Angelia Hutajulu Astia , Ragab Gaafar Gamal , Bt Musa Faizah
Published: November 2016

Thin laminations reservoirs of sand and shale, which contains hydrocarbons was determined in some reservoirs at Malay Basin, but not identified as hydrocarbon bearing, or hydrocarbon-in-place are not properly quantified. The net pay and hydrocarbon saturation assessment are a challenge in thin-layered and shaly sand reservoir, with low resistivity and low contrast log response. However, there are several productive reservoirs with similar characters. In thin lamination shaly-sand, fine grained of sand, silt and clay were distributed within the hydrocarbon bearing reservoirs. The character of these reservoirs will be determined as a low net reservoir and reduce the apparent resistivity. Most of the hydrocarbon saturation is difficult to be assessed by conventional log interpretation and leads it as low pay zone or water bearing reservoirs. Meanwhile, the higher cost of exploration and production will determine these as un-commercial reservoirs and the opportunity of this reservoir will often be missed.

The factors that affect the low resistivity low contrast include bed thickness, grain size, mineralogy, structural dip, clay distribution and water salinity or any combination of the above will affect the well logging instrument to measure lower resistivity response than would ordinarily be expected inside a good productive formation. This response of low resistivity-low contrast is due to the low vertical resolution of the conventional logging tools, which can not measure thin-bedded pay zones.

One of the case studies which is presented in this paper, the sequence of sands reservoir from Peninsula, Malay basin has low net reservoir due to high shale contain and low resistivity, almost close to shale resistivity. The well testing and lab analysis prove this interval as oil bearing in the present work we conduct the evaluation of low resistivity-low contrast for thin bed lamination of shaly-sand reservoir to optimize the hydrocarbon saturation quantification. Some approaches were performed to determine shale distribution and saturation hydrocarbon. Thomas-Stieber method was used to determine the shale distribution in the reservoirs and its properties. The horizontal resistivity (Rh) and vertical resistivity (Rv) was acquired on the next closest well to calibrate the resistivity model which using Hagiwara macroscopic anisotropy approach. And Waxman-Smitts method was performed to calculate the final fluid saturation. The hydrocarbon saturation results in thin-bedded reservoirs in the current study was improved this interval was defined as pay zone by perforated it and it produces 600 oil bbl/d and 0.2 mmscf/d. This method can be used for others wells and other reservoirs which have a similarity of geological forces to improve the resource assessment, especially to assess hydrocarbon saturation in pay thin-bedded reservoirs.
Selection and Optimization of Spacer Surfactants for Enhanced Shear-Bond Strength
Authors: Deshpande Abhimanyu , Dumbre Maithili , Palla Venkata Gopala Rao , Rayaprolu Anirudh
Published: November 2016

Well-executed cementing is a key parameter for achieving successful zonal isolation to help ensure long-term integrity of the wellbore. Casing centralization, design of wellbore fluids for maintaining density hierarchy, rheological hierarchy and compatibility, and efficient mud displacement are some important factors that affect the efficiency of the cementing operation. For achieving efficient mud removal, and for keeping the drilling mud from direct contact with cement slurry, typically spacer fluids are pumped before cement placement. This can also aid cleaning the casing and formation surface of oil film, thereby helping achieve good bonding with the set cement.

Spacers are usually water-based fluids with added surfactants for cleaning the casing and formation surfaces. This surfactant pack is usually optimized using bulk conductivity measurements such that an equi-volume mixture of spacer fluid and mud forms water-external emulsion. However, this might not ensure rheological compatibility between the optimized spacer and the drilling mud at all possible volume ratios. In addition, because the conductivity is a bulk property measurement, it does not give enough information about its wetting characteristics with the casing surface for better bonding.

In the present work, a spacer surfactant optimization procedure is evaluated for three different combinations of drilling mud base oil and the surfactant packs. After surfactant pack optimization, the rheological compatibility between the drilling mud and spacer fluid is measured. The rheological measurements showed that not all volume combinations of the optimized spacer and the drilling fluid are compatible. Hence, the spacer surfactant pack is re-optimized for removing these rheological incompatibilities. Further, shear-bond experiments are conducted to measure the efficacy of spacer to clean the casing surface. It is observed that the shear-bond strength varied between the combinations of drilling fluid base oil and the surfactant pack. This study helps in terms of identifying and optimizing a suitable surfactant pack for given drilling fluid base oil for achieving better compatibility and casing cleaning.
Solution to Coning Under Simultaneous Three-Phase Flows for Multiple Vertical Wells
Authors: Phaiboonpalayoi C. , Johns R. T.
Published: November 2016

Coning of unwanted fluids is a significant problem in the reservoir where fluid contacts are close to the producing zone. Coning can lead to a dramatic loss of reservoir energy and result in reserve reductions. The critical production rates to avoid coning can be determined using reservoir simulation. However, history matching are time-consuming and expensive and an accurate result can only be achieved by using small grid blocks near the wellbore.

In this paper, we find a new analytical solution for simultaneous flow of three phases for a single well, and for superposition of multiple wells. The analytical derivation assumes vertical equilibrium, in that any perturbation in the vertical direction is instantaneously equilibrated. Such an assumption gives maximum crossflow and therefore maximum upward and downward coning of the phases. The solution allows for capillary pressure, permeability, and relative permeability variation in the vertical direction.

The new solution is applied to horizontal well modeling using the solution for multiple vertical wells. The new solution also provides an important benchmark for numerical simulation. The physical windows for the phase flow rates from Ansari and Johns (2006) is extended here for this complex case of simultaneous three-phase flow.
An Integrated Approach in Designing an Optimum Single Well Chemical Tracer Test of Hardness Tolerance Surfactant-Polymer, First in Offshore Malaysia
Authors: Zakaria N. , Ghadami N. , Berok S. M. James , Sedaralit M. , Raub M. , Zulkifli N. , Manap A. Abdul
Published: November 2016

The Single Well Chemical Tracer (SWCT) method has proven to be a reliable technique to measure near wellbore residual oil saturation (Sor) and to validate the chemical formulation developed in the laboratory prior to full field Chemical EOR (CEOR). The objective of this work is to establish an inclusive SWCT test program of a new generation Surfactant-Polymer (SP) that can withstand seawater via a holistic approach, making the project first in the world for offshore application.

A robust study was carried out to develop an optimum SWCT pilot to validate the chemical effectiveness in terms of Sor reduction between post waterflood and SP flood in one of the Malaysian offshore fields. This paper demonstrates a seamless integration from multi-disciplinary teams to propose a SWCT concept, commencing from a vigorous R&D program to a comprehensive subsurface and surface evaluations, as part of derisking steps of key risks and uncertainties. The SP formulation has demonstrated encouraging outcome in the laboratory. Hence, the results and lessons learnt are required to be validated in the field.

Some critical parameters were properly quantified during the fluid-fluid and fluid- rock evaluations in the laboratory such as surfactant-polymer compatibility, phase behavior, interfacial tension, Sor reduction and adsorption to ensure the chemical formulation readiness. The test was designed to utilize one existing producer with minimal workover for cost optimization. A detailed well screening review was performed on the existing wells, with the integrity check surpassed the selection criteria. This consideration is essential to ensure that the selected wells are fit for pilot program, without compromising on pilot objectives. Other selection criteria also included reservoir quality, pay zone thickness, gas interference, and high water cut wells, wells configuration and status. Subsequently, detailed numerical modeling works were performed, including the coreflood modeling for scaling up chemical parameters and radial modeling to reinforce the SWCT test design. Sensitivity analysis were conducted to find the optimum preflush, slug size, and injection rate and flowback period. Similarly, the surface team looked at various concept select options within the constraint imposed by the offshore environment and aging facilities. Due to these challenges, a floating facility, which is an accommodation work barge was selected as the most feasible option to outfit the chemical mixing, injection and back production equipment.

This paper elaborates in further details the workflow process from laboratory, well selection and numerical modeling as part of designing an optimum SWCT field trial that meeting all required test objectives, especially in an offshore operation.
Computation of Relative Permeability from In Situ Imaged Fluid Distributions at the Pore Scale
Authors: Zou S. , Hussain F. , Arns J. , Guo Z. , Arns C. H.
Published: November 2016

Image-based computations of relative permeability require a description of fluid distributions in the pore space. Usually the fluid distributions are computed on the imaged pore space. Recent advances in imaging technologies have made it possible to directly resolve actual fluid distributions at the pore scale, thus capturing a large field of view for arbitrary wetting conditions, which are numerically difficult to reproduce. In previous studies fluid distributions were not imaged under in-situ condition, which may cause oil (non-wetting) phase to snap-off. Consequently computed oil relative permeability is underestimated particularly at low oil saturations. This study extends our previous work by imaging fluid distributions under in-situ conditions as basis for the numerical computations.

In this study, we perform steady state flow test on a homogeneous outcrop sandstone (Bentheimer) core. First, the dry core is imaged in our micro-CT facility. Afterwards the core is fully saturated with 0.4 molar NaI solution. The saturated core is then mounted in a specially designed flow cell which allows the flow experiment to be carried with the core mounted on the CT scanner. Afterwards steady state injection of oil and brine is carried out at four different oil/water injection ratios. For each injection ratio, steady state pressure drop is noted and in-situ fluid distributions are imaged under flow conditions. These imaged fluid distributions are used to compute image-based relative permeability. While the measured pressure drops are used to calculate experimental relative permeability.

In conclusion, the match between the relative permeability computed from imaged fluid distributions and experimental measurements is excellent. Results demonstrate that imaging in-situ fluid distributions allows us to overcome significant limitations of our previous work: 1) measured and computed oil relative permeability are in close agreement for whole saturation range and 2) laboratory capillary end effects at the core outlet can be imaged which allows us to apply a correction to the laboratory measured data.
Experiment and Modelling of Massive Fracturing Considering Drainage and Imbibition Process in Tight Oil Reservoirs
Authors: Shuai Li , Yunhong Ding , Bo Cai , Yongjun Lu
Published: November 2016

Spontaneous imbibition is an important process to increase oil recovery in fractured carbonate reservoirs. Due to the nano-scale pores and throats distributed in tight oil reservoirs, capillary pressure became much larger, which may result in a much stronger imbibition.

An experimental and modeling was adopted to simulate drainage and imbibition process in hydraulic fractured tight oil reservoir. Firstly, 400 mm×100 mm×30 mm core samples were used to simulate forced displacement and spontaneous imbibition of fracture surface at in-situ conditions of pressure. Secondly, 1D model for counter-current imbibition was solved on some assumption of relative permeability and capillary pressure, numerical results obtained by COMSOL as verification.

Results have indicated that recovered oil was 0.19 mL in spontaneous imbibition condition while was 0.62mL in combined condition of forced displacement and spontaneous imbibition. Saturation front contacts the sealed end-face much faster with forced pressure condition. According to this phenomenon, it can be inferred that the main direction of aqueous phase in the shut-in period is form large pores to smaller pores. Aqueous phase was pushed into the large pores by forced pressure, and imbibed into smaller pores in the function of capillary pressure. 1D model of 2 phases counter-current imbibition solved with Galerkin method is in correspondence with numerical result at the same assumption. With the increase of dimensionless distance (X) and dimensionless time (T), water saturation profiles were drew and were contrasted with CT scanning.

Forced displacement and spontaneous imbibition simultaneously occurs during fracturing and shut-in duration. Study of this can provide a reference for soaking management and a good way to increase well productivity.
Growth Fault in Longmaxi Shale and its Importance for Sedimentary Distribution and in Situ Stress Direction-A Typical Case from southeastern Sichuan Basin, China
Authors: Wang ZhenXing , Chen JieYing , Pan Feng , Wang DaLi
Published: November 2016

The complex fault system formed due to periods of tectonic movements always raised the risk of shale gas E&P activity. Faults with large displacement can be easily recognized on seismic profile, but mini faults are hard to find even though they have non-ignorable impact on well palnning. This paper ultilzed the borehole image data to distinguish the mini fault and analysised how the mini fault can influence the sedimentary and in situ stress disturibution.

Stratigraphic dip patterns from images, integrated with core data and conventional logs, can ascertain the fault position in the wellbore and help define the fault property, such as fault azimuth, dip amplitude, fault displacement, and the fault-related geological deformation. The dip patterns showed abrupt change around the fault breakpoint at which depth the image structure was disordered, the cores broke into pieces, and the marker values on the conventional logs were missing compared with adjacent wells. Sedimentary features observed on the images also revealed different structures between hanging wall and foot wall of the fault in the wellbore. All of above proved the existence of the normal fault.

Cross section images were used to evaluate this fault and its associated depositional architecture. In the target shale interval, the wells on the cross section show strong comparability of thickness and stratigraphic dip patterns which are mainly green patterns. However, the dip patterns in the same interval demonstrated green-red-green patterns in the well where the fault was discovered. Morover, a set of sandy turbidities overlied on the target shale can be found in all of the wells on the section. It has thinner trend towards the south, but unexpectedly became thicker in the well with the fault. A great amount of syngenetic deformational structures were also recognized on the image of the hanging wall of the fault, while the foot wall is dominated by parallel bedding and low angle cross bedding. Those phenomenon indicated that the fault is a typical normal growth fault. Furthermore, the in situ stress direction reflected by the wellbore failure demonstrated that the in situ stress changed its direction around the fault plane. It is concluded that the fault controlled the sedimentary distribution in the depositional period and influenced the in situ stress direction during tectonic movements.

The analysis of the stratigraphic dip patterns from the images complemented the accuracy of seismic data in the geological structure interpretation. The understanding of the growth fault have realistic meaning in both studying the sedimentary facies distribution and predicting in situ stress direction.
Geostatistical Pre-Stack Inversion for Thin-Bedded Reservoir Characterization in Bongkot Field, Gulf of Thailand
Authors: Promrak W. , Tubsrinuan N. , Asawachaisujja S. , Pabchanda S. , Boonyasaknanon P. , Srisuriyon K. , Sognnes H. I. , Shaw R. K.
Published: November 2016

A geostatistical seismic pre-stack inversion was carried out over a producing gas and condensate field in the Gulf of Thailand, North Malay basin. As the main reservoirs are thin-bedded stacked fluvial deltaic sands of Miocence age, detailed mapping of reservoir distribution was challenging due to limited seismic resolution. To overcome such challenges, a pre-stack geostatistical inversion was initiated. The input dataset consisted of six wells and 250 km2 of 3D seismic data. The well log data passed through rigorous QC and rock physics analysis, while the seismic data were subject to preconditioning to ensure improved CDP gather flatness and signal-to-noise ratio. Starting from geostatistical modeling, the inversion generated multiple detailed realizations of lithology and elastic properties based on Bayesian Inference and Markov-Chain Monte Carlo methods. Statistic of multiple resulting realizations also implied a range of possible solutions of this non-unique inverse problem. In addition, petrophysical properties were simulated by using statistical relationships between inverted elastic and petrophysical properties. By integrating high frequency well logs with low frequency seismic, the geostatistical inversion process provided high vertical resolution and captured spatial variations of the various lithology types and their respective elastic properties. Since a majority of the stacked gas sand reservoirs in the area were below the tuning thickness, the geostatistic inversion results provided significantly improved insight to facies distribution. According to blind well results, precision of net pay estimation provided by the geostatistical inversion improved from 40% to 83%, compared to predrilled prognosis; while, pay estimation uncertainty was reduced by 30%. The generated petrophysical volumes also showed more detailed spatial variation, and can be used to improve in-place volumetric calculations and support field development planning.
South Atlantic Recent Slope Setting Discoveries, the Proven Pathway to the Ultra-Deep Water Basin Floor Fan Play
Authors: Hodgson Neil , Rodriguez Karyna , Intawong Anongporn , Eastwell David
Published: November 2016

Oil exploration has become a journey into ever deeper water as increasing competition for a smaller prize in the accessible shelf or failed rift basins has encouraged oil companies to explore the continental slopes, where success has been episodic and predominantly associated with stratigraphic channel plays. As a safer and highly rewarding alternative, we propose the ultra-deep water basin floor fan in the deep water abyssal plains setting as the future oil play for this century.

An extensive dataset of modern long streamer 2D seismic in ultra-deep water along both sides of the South Atlantic margins has been employed to identify a regional source rock and kitchen areas, while depth domain seismic profiles have been utilized to reveal the true geometries of basin floor fans on either side. A model of an ultra-deep water basin floor fan play with its associated resource potential has been put together and indicates a huge trapping geometry in the depth domain where it becomes apparent that the basin floor fans deposited at the base of slope directly overlying the mature source rock are in fact not dipping out to sea, but dip landward, eliminating the up-dip seal trapping risk.

Basin floor fan examples observed in Mauritania, Senegal and Sergipe have all been calibrated with seismic attributes associated with major recent discoveries. These have also been integrated with results from source rock maturity modelling and analysis of satellite seep clusters, both of which provide strong evidence of an oil generative system.

An identical geometric relationship can be seen on PreSDM data from other basins, for instance the Pelotas Basin in Brazil/Uruguay, Gabon, Namibia/South Africa and even Somalia on the eastern side of Africa. In addition, settings in South East Asia with similar potential but subtly different play types have been reviewed, to indicate how these systems might work in ultra-deep water outboard of broadly destructive margins.

The surprising result is that, significant areas around the globe below 3,000 metre of water, in the lower slope and abyssal plain setting, appear to have potential for a working hydrocarbon system.
Post Rift Oligocene Marine Source Rock, a New Petroleum System in Greater Bangkanai, Upper Kutai, Indonesia
Authors: Nugroho Bayu , Guritno Elly , Mustapha Haryo , Darmawan Windi , Subekti Ari , Davis Carey
Published: November 2016

The long-held view and general understanding on the source rock within the Upper Kutai Basin is that it comes from the fluvial-deltaic facies. This deltaic coals and carbonaceous source rock has been proven generating gas with oil in Western Indonesian tertiary basins such as the Miocene Balikpapan Formation in the Lower Kutai Basin, Tanjung Formation in the Barito Basin and TalangAkar Formation in the South Sumatra Basin. The Oligocene carbonate play in the Upper Kutai Basin is under-explored, with exploration historically focusing on the Miocene deltaic and turbidite plays. These carbonates mainly consist of the UjohBilang or Berai equivalent Formation which outcrops along the southern and western margin of the basin, and is seismically imaged in the subsurface, forming on isolated basement highs and large platform areas.

Ophir Energy's Kerendan Gas Field in the Bangkanai PSC is the only Oligocene carbonate gas producer in the Kutai Basin. Development drilling on the Kerendan Field and the West Kerendan-1 exploration well has provided new information which, together with a re-evaluation of the existing carbon isotope and other geochemical data has led to a reinterpretation of the source rocks for Kerendan gas. The gas was previously postulated to be generated from Eocene terrestrial source rocks similar to the source rocks that generated oil and gas in the neighboring Tanjung Field in the Barito Basin, 100 kms to the South. The recent carbon isotope data from the Kerendan wells reveals that the gas in the Oligocene carbonate reservoir in Kerendan was generated from a marine source rock and is not terrestrial in origin. In addition there is also a terrestrial component within the gas found at the younger stratigraphic interval.