bluuebunny/crossref_metadata_2025 huggingface dataset:
Construction of Digital Oil for Investigation of Crude Oil Properties at Different Thermodynamic Conditions
Authors: Sugiyama Shumpei , Liang Yunfeng , Murata Sumihiko , Matsuoka Toshifumi , Morimoto Masato , Ohata Tomoya , Nakano Masanori , Boek Edo S.
Published: November 2016

Digital Oil, which is a full molecular model of crude oil, opens a new era for understanding the behavior of crude oil at a wide range of thermodynamic conditions. In this study, a Digital Oil model for a domestic oil field was constructed based on analytical experiments, including gas chromatography data, elemental composition, molecular weight from gel permeation chromatography, 1H-NMR and 13C-NMR spectroscopy data. The gas and light fraction components were analyzed by gas chromatography, and 109 kinds of molecules, including n-alkanes, iso-alkanes, naphthenes, alkylbenzenes, and polyaromatics (with maximum 3 aromatic rings), were modeled. On the other hand, the heavy fraction and asphaltene components were represented by molecular mixtures using an improved quantitative molecular representation (QMR) method, which were consistent with analytical experiments, such as elemental composition, molecular weight from gel permeation chromatography, 1H-NMR and 13C-NMR spectroscopy data. Due to its low weight concentration of asphaltenes (~0.1 wt%), the Digital Oil (i.e. the live oil) model was constructed by mixing all the above molecular models except for the asphaltene model. With this model, densities of the live oil were calculated at a wide range of pressure under reservoir temperature by molecular dynamics simulations. At pressures above 163 bar, the densities were calculated by assuming single phase. The results show very good agreement with experimental data of the crude oil. At pressures below 163 bar, components in a liquid phase of the Digital Oil were predicted by flash calculations using equation of state (EOS) model at selected pressure conditions. In this case, the calculated densities of the liquid phase also coincided with the densities of the experiment. Thus, we could observe reproducibility of the Digital Oil in terms of density at a wide range of pressure. It provides a good example on using simulation tools across different scales with multi-physics models (i.e. EOS and molecular models). Digital Oil is a versatile tool, which can be applied in both upstream and downstream industries for various problems. Since most of EOS models were developed before new field advancement of asphaltene and heavy oil molecular models (including ours here), attention and hopes were drawn for further application of Digital Oil conception in oil industries.
Reservoir Characterization of Horizontal Wells in CD Carbonate Formation with Advanced LWD Technology
Authors: Abrar Budi , Ernando Zeindra , Carigali Petronas , Pasaribu Ihsan , Permanasari Dian
Published: November 2016

The CD Carbonate of Ngimbang Formation in East Java basin was deposited in early Oligocene and divided into 5 reservoir targets for development. These reservoir targets were subdivided into different flow units, predominantly due to secondary porosity resulting from karst processes. Identifying these karst zones therefore became important for formation evaluation. Classic high resolution borehole images, combined with sonic, density and neutron logs, and NMR are the most commonly used tools to identify secondary porosity. However, due to the horizontal well design, conventional wireline logging was no longer possible thus Logging While Drilling (LWD) has become the primary data acquisition method. The LWD tool selection criteria have to meet both the geosteering and formation evaluation objectives by considering all drilling challenges. Even though all these measurements are currently available with LWD technology, the complexity of the long horizontal well trajectories and associated drilling risks have been assessed as being too high to run all the LWD services. Therefore, a different technique is required to identify karst zones and to determine saturation along the deeply-invaded karst intervals.

A statistic-based correlation technique using principal component variance between advanced measurements from the multifunction LWD tool such as sigma, neutron capture spectroscopy, and standard measurements such as gamma ray, neutron porosity, density, caliper, and resistivity invasion profile is used to show an indication of karst- or matrix-dominated porosity. The spectroscopy provides accurate lithology volumes and information on grain properties. A simultaneous sigma–resistivity inversion technique is used to determine Archie's parameters in zones where the water salininty is known. The applicability and limitations of the technique are discussed for this particular reservoir environment. The combination of all these techniques along with information from state-of-the-art reservoir mapping technology has provided more complete characterization of the reservoir along the horizontal section.
Three Generations of Wellhead Platform
Authors: Phanichtraiphop Pheerasak , Lertwanichwatana Ratchada , Kiewlek Yoottapong , Sillapacharn Thitinun , Tivanantakorn Weerapong , Sittipod Suchaya
Published: November 2016

PTT Exploration and Production Public Company Limited (PTTEP) is the operator of offshore gas fields in the Gulf of Thailand (GoT), consisting of two major gas fields, namely Bongkot and Arthit. Both assets were initially developed with different partners, therefore, Bongkot and Arthit fields were developed using separate design practices and specifications. Having two different designs of Wellhead Platform (WHP) caused ineffective asset management and operation, therefore, PTTEP decided to generate PTTEP's own specifications and develop a single design of future WHP to be used in both fields, namely Conventional Wellhead Platforms (CWP). However, both Bongkot and Arthit Fields still have undeveloped reserves with varying amounts of recoverable hydrocarbon fluids. As the estimated reserves are not suitable for the capital expense of CWP, these fields are considered as Marginal fields. To secure Thailand's energy supply, PTTEP has designed two alternative WHP designs for sub-commercial prospect reservoirs. The first alternative WHP for marginal fields, called "Medium Facilities Platform (MFP)", is intended to reduce investment cost while maintaining the same operational functions as CWP. MFP could improve economics level in which several prospects become feasible to develop. However, MFP was still not capable to economically develop the remaining small gas reservoirs. Therefore, the second alternative WHP for marginal fields, called "Small Facilities Platform" (SFP) was initiated to further optimize from MFP. With three (3) designs of WHP, one design (CWP) for commercial reserve and two designs (MFP & SFP) for sub-commercial reserve, PTTEP can achieve flexibility in field development by matching suitable platform design with reservoir requirements.

With the current low oil price crisis, oil and gas companies must strive to develop profitable new projects to survive and thrive in the sustainable future. PTTEP has strong determination to continue moving forward and overcome tough challenges. CWP, MFP and SFP are examples of our passion to explore, produce, and secure energy supply.
Proppant Upgrade by Wettability Alteration
Authors: Wang Chuanzhong , Zhang Kewei , O'Neil Bill , Lu Weibing , Quintero Harvey
Published: November 2016

Proppant plays a key role in maintaining fracture conductivity during well production. Silica sand is by far the most commonly used proppant due to its low cost and availability. However, some of frac sands, especially Tier 2 sand, are not always satisfactory under formation conditions. This work presents a cost-effective and environment-friendly method to improve sand quality through changing surface wettability. Meanwhile, the method can dramatically reduce airborne dust during sand transportation and frac operation.

The new approach is based on sand surface modification with a trace amount of a proprietary chemical, which is an eco-friendly liquid and can modify sand surface properties including wettability from hydrophilic to hydrophobic. The treating process is fairly easy and effective by simply spraying the chemical onto frac sand, as the chemical is designed to readily spread on the surface. As a result, the treating process can be easily set up at sand plants or transload facilities.

The treated sand has been examined by various tests. Crush resistance testing shows that the treated sands generate much less fines than the untreated sands; fracture conductivity measurements indicate the treated sands have significantly greater conductivity to flowback water than the untreated sands. Additionally, the method can also be applied for dust control. Field testing shows that most of the airborne dust can be removed from frac sand. Microscopic observation finds that most of the dust particles are adherent to sand grains.

In summary, this method can be a cost-effective and operationally easy way to improve sand quality as well as control silica dust during sand transportation and frac operation.
Completions Optimization Improvements for Unconventional Reservoirs in Saudi Arabia
Authors: Hamid Osman , Rahim Zillur , Faleh Khaled , Omair Ahmed , Ba-Wazir Omar
Published: November 2016

Successful production from unconventional reservoirs is made possible by horizontal drilling and reservoir stimulation through multistage hydraulic fracturing along the laterals. Although hydraulic fracturing techniques have been widely used for unconventional gas stimulation, a considerable percentage of perforations do not contribute to production. The objective of this study is to integrate the geomechanical, petrophysical and completion parameters to precisely design hydraulic fracture for better hydrocarbon production.

Reservoir characterization and optimizing completion parameters are essential for effective well design to improve staging and perforation placement. Challenges in the design of hydraulic fractures include the proper placement of fracturing ports, perforations, and location of isolation packers. The challenges are due to the large variability in fracture gradients, mechanical and reservoir properties, and petrophysical characteristics along the lateral.

Industry experience shows that injection pressures required to fracture the formation (fracture gradient, FG) often vary significantly along a well and that there can be intervals where the formation cannot be fractured successfully by fluid injection due to high in-situ stress.

Geomechanical and petrophysical evaluations providing rock anisotropy and anisotropic stress properties along the wellbore play a fundamental role in completion and hydraulic fracture design. The paper shows how geomechanical and petrophysical properties from open-hole logs and sonic anisotropy evaluations are integrated to compute reservoir quality (RQ) and completion quality (CQ). Intervals with similar properties are grouped to better understand and optimize hydraulic fracture design and operations. This optimization procedure has been applied in a borehole within a potential shale gas reservoir targeting the hot shale facies formation in Saudi Arabia.

Application of this technology resulted in successful completion with optimum fracture stages and perforation clusters positioning thereby improving the initial flow capacity of the well.
How to Design a BHA Rotary Speed Sweet Spot
Authors: Bailey Jeffrey R. , Minkevicius Andrius , Bolzan Alexander , Wilkins Victoria R. , Pokluda Joshua S.
Published: November 2016

Correct placement of the rotary speed "sweet spot" of a bottomhole assembly (BHA) provides multiple benefits towards achieving the ultimate goal of drilling to section total depth in a single trip. Several field case studies will demonstrate the modeling approach and benefits achieved by selecting a preferred rotary speed range and designing the BHA contact points accordingly.

BHA lateral dynamic modeling is now applied pre-drill in nearly every well the operator drills. In most applications, a proposed BHA design is solicited from the directional service provider with the required MWD/LWD tools for the hole section. This baseline configuration is entered into the model. Alternative configurations are then obtained by moving "contact points" through either stabilizer movement, tool rearrangement, or both.

The model results for a suite of such designs are then generated and compared on a single chart, facilitating selection of the BHA that has the lowest vibration indices over the targeted rotary speed range, usually determined by hole size and drill string modeling. In most instances, BHA designs that have been evaluated and run may be successfully reused, provided that the governing assumptions are still correct.

Redesign of the planned BHAs for a well is considered to be an important part of the well planning process, as early redesign provides the most flexibility to modify the tool configurations. Changes made to BHAs late in the process are constrained by tool availability and logistical considerations.

The process of BHA redesign and "tuning" for the desired operating parameters provides greater control over the drilling process, with fewer surprises resulting from poor drilling dynamics. Gaining more control over drilling dynamics has helped to remove one of the most pernicious variables in the well construction process.

In many runs, BHA designs with model-predicted vibrational sweet spots match field observations, and good drilling performance has helped the programs stay on target. Vibration minimization through proper design and operation of the BHA facilitates drilling objectives that include reaching section depth in fewer trips and providing acceptable borehole quality to run casing to depth.
Sand Production Management the Critical Challenge in Zawtika Gas Production
Authors: Junmano T. , Lee B. , Grant G. , Raipairi P. , Viriyasomboon N. , Nopsiri N.
Published: November 2016

To ensure safe operations and to maximize well potential, PTTEPI has formulated a sand production management strategy to reduce risks due to sand production while extracting natural gas resources from the young clastic reservoirs formed during Plio-Pleistocene geological sequence. Over the 2 years of historical production, the strategy has been fine-tuned and enhanced to improve its effectiveness in managing sand production.

The strategy integrates efforts from both subsurface and surface disciplines. It covers initial well completion design to address the need for sand control, continuous recording and analysis of performance data after a well is put on production to monitor and manage sand production within acceptable limits, data acquisition programs to obtain additional information for analysis of sand production, and remedial and mitigation initiatives to address sand production. The following sections will discuss, in more detail, each component of the sand production management strategy.
Evidence for Mesozoic Marine Source in the Western Gulf of Thailand
Authors: Sayers I. L. , Malasri C. , Farrimond P. , White R.
Published: November 2016

This paper documents the findings based on interpretation of the geochemical composition of oils from the Bualuang Field located in the western Gulf of Thailand, and how these oils compare with other oils and potential source rocks in the region. The Bualuang Field is located in Block B8/38, on the eastern flank of one of a series of north-south trending, Tertiary half-grabens which are part of the greater Western Basin.

Eight oil samples from five wells on the Bualuang Field were analysed using gas chromatography (GC), gas chromatography-mass spectroscopy (GC-MS) and carbon isotopic techniques. Selected samples were further analysed by GC-MS-MS. This paper provides a review of these analyses, presenting key geochemical evidence for the likely age and facies of the source of this oil. A comparison is then made between the Bualuang Field oils and other oils from the immediate surrounding area as well as more regionally. In addition, the oils are considered against potential Mesozoic source rocks observed in peninsular Thailand.

The molecular and isotopic analysis of the Bualuang oils show strong similarity, and origin from a carbonate facies (probably marly) as indicated by dominance of C29 hopane over C30 hopane, presence of significant C30 30-norhopane, abundance of C24 tetracyclic terpane and low amounts of diasteranes. Furthermore, the oils are believed to have a marine origin due to the presence of C30 steranes (confirmed by GC-MS-MS), a C26/C25 tricyclic terpane ratio in excess of 1, and the stable carbon isotopic composition. The source of the Bualuang oil is considered older than Tertiary because of the absence of oleanane (typically significant in Tertiary oils), the dominance of 27-norcholestanes (24-norcholestane ratio ca.0.18) and a low C28/C29 sterane ratio (0.58-0.65). Correlation with other oils near Bualuang indicates that this source facies extends further north, with some subtle differences. More regionally clear differences can be observed between the Bualuang oils and other Tertiary oils recognized as either lacustrine or terrestrial in origin. The current study confirmed Jurassic-aged potential source in shales in peninsular Thailand; however, these are quite different to the source for the Bualuang oil. Previous published data for Cretaceous-aged potential source rocks onshore also do not provide a strong correlation.

Importantly this paper provides strong, albeit indirect, geochemical evidence for an additional oil-prone source to consider within the western Gulf of Thailand, which is believed to be Mesozoic in age. One of the key exploration challenges is related to identifying the presence and extent of such a Pre-Tertiary source on seismic data.
A Comprehensive Geomechanical Study for Deep-Water Field Development Planning: A Case Study from Southeast Asia
Authors: Younessi A. , Khaksar A.
Published: November 2016

Several concerns arise at the field development planning stage which may be only answered by geomechanical studies, such as wellbore stability analyses, sanding risk assessments, and studies of compaction and subsidence during the life of the field. These issues can be very important in large projects in deep-water environments. A comprehensive geomechanical study was conducted for an offshore deep-water gas field in Southeast Asia as part of the field development planning.

The study covered a wide range of geomechanical studies from drilling to production stages for the entire life of the field. The geomechanical model was built based on the available logs and data from the exploration and appraisal wells drilled in the field. The model was then used for several geomechanical applications; a) wellbore and fault stability analysis to investigate the effect of the well trajectories on mud weight recommendations and casing design, b) sand production prediction analysis to study the risk of sanding for different completion scenarios, and c) compaction and subsidence analysis to study the impact of depletion on the platform and subsurface designs.

A wellbore stability analysis was conducted to investigate the effect of wellbore trajectory on the safe mud weight window. The analysis suggested that the collapse pressure for any well in the field is dependent on the deviation of wells rather than their azimuths. The impact of the stability of the natural fractures and faults on the upper bound of the safe mud weight window was investigated in detail. The analysis showed that the mud weight required to reactivate the natural fracture and fault intersecting the wells is above the upper bound of the safe mud weight window defined by the wellbore stability analysis.

The sand production prediction analysis showed that sanding is expected from the early stages of production for both open-hole and cased and perforated completions. The analysis suggested that selective and oriented perforations may only delay or reduce the risk of sanding and cannot eliminate it entirely. The compaction analysis showed that the maximum compaction is less than 1% for all reservoirs. This is significantly lower than the general criteria of 3% – 5% which may cause problems for casing and completion systems. Moreover, the maximum total calculated subsidence at the seabed is expected to be below the engineering design limits.

All the methodologies and approaches used to conduct the above mentioned geomechanical analyses, and interpretation of the results are thoroughly explained in this paper. This study highlights the importance of the geomechanical studies for decision making in deep-water field development planning.
Mapping the Bakken with Azimuthal Gamma Ray
Authors: Carrilero Susana Gutierrez , Hinz David , Moake Gordon , Parker Timothy , Carson Dan
Published: November 2016

This paper defines current geosteering practices in the Middle Bakken formation using conventional gamma-ray detectors and discusses the use of a new azimuthally sensitive gamma-ray sensor for more accurate well placement in the target formation.

Two wells were drilled in the Middle Bakken formation using both a conventional gamma-ray detector and a new azimuthally sensitive gamma-ray sensor equipped with an inclinometer to provide continuous inclination. Because omnidirectional gamma-ray measurements can be ambiguous, especially when markers have similar gamma-ray readings, azimuthal gamma-ray wellbore images were used to infer the relative stratigraphic movement of the drilling assembly through the formation.

The two lateral wells presented in this study were drilled entirely inside the target zone between the objective gamma-ray markers. Both real-time and memory data were analyzed using borehole imaging software. Relative and true formation dip angles were calculated after estimating the best depth-of- image. The use of azimuthal gamma-ray images made it possible to determine if the wellbore was moving up or down stratigraphically. A more accurate geological correlation based on the image interpretation, together with an enhanced survey using continuous inclination, made it possible to map the top and base Middle Bakken surface locations. A comparison was established with laterolog resistivity images from the same area that were of higher resolution and higher cost, validating the use of azimuthal gamma-ray for dip calculation.

The azimuthal gamma-ray measurement provides insight into stratigraphic well placement beyond what can be determined from omnidirectional measurements. Data acquired from the gamma-ray image, when combined with enhanced directional-survey measurements, can help to further refine geosteering decisions and reduce uncertainty in wellbore placement.

This paper presents an application of a new, low-cost measurement to allow for better unconventional well placement in difficult-to-interpret situations. As this technique is more widely applied, it may lead to a step change in how lateral wellbores are positioned stratigraphically to increase reservoir exposure.
Consistently Integrating Static and Dynamic Data in the Facies Model Description Using an Ensemble Based Approach
Authors: Sætrom Jon , Phade Anish , Vinther Morten Loell , Munck Tore Felix
Published: November 2016

Building reservoir models that consistently honors static and dynamic data is a difficult, if not impossible, task using traditional approaches resulting from limitations of existing tools and best practice workflows. The crux of this task has traditionally been to utilize dynamic data in the facies modelling process, which is often the cornerstone of the reservoir modelling workflow. Hence, failing to integrate the static and dynamic data measurements in the facies modelling process consistently can dramatically reduce the predictability of the generated reservoir models. In this paper, we efficiently solved this problem using an ensemble-based approach in combination with an adaptive pluri-Gaussian facies modelling scheme. We demonstrate the procedure on a medium size field with 15 years of production history. During the dynamic data conditioning, clear trends are established in the facies model throughout the reservoir, which provide a good indication of the expected facies distribution and associated connectivity. Having a thorough description and understanding of the subsurface uncertainties - especially when it comes to the facies model description - is key to improved reservoir management decisions when considering both optimal drainage strategies and well placement.
Reservoir Characterisation and Modelling of the Nang Nuan Oil Field Thailand
Authors: Lurprommas T. , Hamon Y. , Lerat O. , Nantawuttisak J.
Published: November 2016

The main objective of this study is to construct a geological and static reservoir model of the interpreted karst reservoir in Nang Nuan Oil Field (NNN) in order to obtain hydrocarbon accumulation zone of the field. The target intervals are Permian Ratburi carbonate and Tertiary polymitic conglomerate which are suspected to be potential reservoir. This study started with the review of previous literatures and all available subsurface information such as conventional core, electric logs, production data, 3D seismic etc. Hence, the geological model was reconstructed and proposed to use for static reservoir model. Electrofacies was identified during the data preparation phase in order to get the link of lihofacies and electric log including petrophysical properties. The numerical model was constructed following the basic static reservoir modelling workflow. Regarding integration of all information in hand, the geological model of this study is partly different from the previous model. The most significant difference is the reservoir facies. This study proposes Tertiary conglomerate facies from interpreted alluvial fan deposits as the reservoir instead of Permian carbonates meanwhile the dissolution is still the main key of porosity development. In term of numerical model, the sequencial indicator simulation is used for distribute facies and petrophysical properties in spatial. According to the result of this study, the reservoir geometry and porosity development were changed from the existing model. The geometry of carbonate karst tower is restricted in term of the area meanwhile Tertiary conglomerate from alluvial fan deposits is more extensive and the key that advocates the increasing of dissolution is stratigraphic break. The result of this study changes reservoir facies which impacts possitively to distribution of petrophysical properties. Thus, the new model may lead to re-think of the field value and make it becomes viable again.
From Single Wireline Formation Tester Station to Reservoir Characterization: A Workflow to Evaluate Reservoir Compartmentalization
Authors: Bertolini A. , Betancourt S. , Duangprasert T.
Published: November 2016

Even with the sophisticated reservoir characterization techniques available today, the oil and gas industry develops and manages reservoirs under considerable uncertainty about their true properties. Two examples of these uncertainties particularly critical in deepwater projects are reservoir compartmentalization (lack of lateral and/or vertical connectivity because of geologic features or organic barriers) and flow assurance, both of which have a significant impact on reservoir understanding, field development planning, and productivity forecasts. Reservoir compartmentalization has been proven to be a persistent problem that mandates new methods and tools for reservoir evaluation.

Some operators have aggressive targets to bring their deepwater fields to production within 7 years of discovery. This implies that important decisions on field development have to be made with very limited information. The increased complexity of new discoveries in deepwater settings and the associated high developments costs demand improvements on reservoir analysis. Reservoir pressure analysis and downhole fluid analysis (DFA) from wireline formation testing (WFT) tools have enabling cost-effective assessment and measurement of fluid composition required to assess reservoir connectivity and early diagnostic of flow assurance issues. Pressure and DFA data coupled with the conventional cubic equation of state for dissolved gas-liquid analysis and the new Flory-Huggins-Zuo equation of state (FHZ EOS) for dissolved solid (asphaltene)-liquid analysis provide the opportunity to model the heavy-end fluid distribution from heavy oils to condensate. New data interpretation workflows centered on pressure analysis and DFA provide information on connectivity and fluid behavior useful for reducing the uncertainty when generating a field development plan.

A generic deepwater field is used here to illustrate the process of integrating wireline formation tester data (DFA and pressure) acquired during field exploration and appraisal in the generation of a field development plan (FDP). WFT data is used to evaluate the variation of fluid properties and pressure gradients in the reservoir and delineate compartments. This data improves understanding of the reservoir structure and gives a model that is closer to reality that is used in an optimization workflow to generate a field development plan (FDP). Another (optimal) FDP is also generated using the reservoir model created when WFT information is not used. These two FDPs based on approximate reservoir models are implemented on the "real" reservoir structure, known in this exercise, to quantify the value of WFT information.
Dynamic Embedded Discrete Fracture Multi-Continuum Model for the Simulation of Fractured Shale Reservoirs
Authors: Chai Z. , Yan B. , Killough J. E. , Wang Y.
Published: November 2016

The wide implementation of hydraulic fracturing in shale reservoirs and the interactions among hydraulic fractures, natural fractures and the shale matrix have brought great challenge for reservoir studies using conventional finite-difference-based reservoir simulators. This work establishes a dynamic approach for the simulation of fractured shale reservoirs that incorporate the embedded discrete fracture model (EDFM) as well as the multiple porosity model, which is necessary for simulating the complex transportation process in shale reservoirs.

In this paper, we extend the EDFM approach for fractured shale reservoirs to a multi-continuum context, in which one fracture segment can have mass transfer with multiple parent grid blocks in favor of the complex porosity types of shale formations. The reservoir model can be updated dynamically during the simulation with our in-house simulator to consider the change of the fracture network due to fracking and refracking at different stages of field development. This is achieved by altering the effective non-neighbor connections with time that are associated with the fracture system. Therefore the reservoir with a changing fracture distribution can be modeled with a single simulation. The formulation is based on finite volume rather than finite difference to facilitate the unstructured nature of the reservoir model.

The result is compared with the explicit fracture model with PEBI grid blocks to evaluate its accuracy. For the test case of a horizontal well with multiple hydraulic fractures and large scale natural fractures, the simulation result can be matched with great accuracy. Sensitivity analysis to grid refinement is also conducted, which proves the model only need moderate grid refinement to obtain desirable accuracy.

This work established a more flexible and efficient yet more accurate approach for fractured shale reservoir modeling, with the emphasis on improving the ability to model the fluid transportation among different porosity types. The proposed model improves the simulation by reducing the complexity of the gridding process, cutting the total number of grid blocks, and significantly decreasing the CPU time. It provides a coherent method for characterizing the fluid transportation in fractured shale reservoirs, which is usually a difficult task with traditional reservoir models.
Development of Marine Seismic Vibrator towards Realization of Shear Wave Source with No Touch-Down to Seafloor
Authors: Ozasa Hiroaki , Sato Fumio , Asakawa Eiichi , Murakami Fumitoshi , Jamali Hondori Ehsan , Takekawa Junichi , Mikada Hitoshi
Published: November 2016

We developed a towed marine seismic vibrator (MSV) as a new type marine seismic source that employed the hydraulic servo system for the controllability both in phase and in amplitude of the signal being emitted. MSV could mitigate a risk of the impact to the marine environment while satisfying the necessary condition of seismic sources and could enable shear wave analysis in the marine environment to improve the situation of marine seismic data acquisition. We conducted a sea trial to acquire seismic reflection data using a downsized MSV and a streamer cable above the seafloor where a cabled seismic observatory has been deployed. A series of controlled chirp signals was generated by MSV. The sea trial showed that penetration of seismic signals generated by the downsized MSV was comparable to that by an airgun of 480 cu-inch with a slight inferior signal-to-noise ratio. We could observe the improvement in the penetration of seismic signals for the downsized MSV towed deeper that is preferable to generate shear waves. Finally, we could observe that the amplitude of shear waves, which are reflected back from the subseafloor structure, is acquired by the horizontal components of a seafloor installed seismometer.
Simulation Study of Foam Displacement at Pore and Reservoir Scale
Authors: Xia Jun , Li Xiangfang , Zang Jiali , Zhou Tong , Li Jing , Bai Jie , Jiang Mingjie , Zhang Zenghua , Chen Yu
Published: November 2016

Although the microscopic mechanisms of foam generation, migration, coalescence and collapse are well studied in many laboratory experiments, it is still inappropriate to apply the experimental results to the field directly. At reservoir scale, the velocity and shape of foam displacement front should be emphasized rather than the foam behavior.

Based on a heterogeneous low permeability oil reservoir with horizontal fractures which locates in western China, a numerical foam flooding simulation model is built. Sensitivity analysis is conducted through changing parameters in three aspects. For the first aspect, geological properties such as reservoir permeability, porosity, oil saturation as well as horizontal fracture aperture are discussed. The second aspect includes foam half-life and its adsorption amount on formation rocks. In the last aspect, injection parameters like gas-liquid ratio, injection circle, and injected pore volume of foam are discussed.

Simulation results demonstrate that the foam displacement velocity are largely affected by the formation permeability and porosity. Large pore size means that bubbles population could be easily created with the result of great increase of foam resistance capacity. The foam flooding front moves faster with increasing porosity and permeability when they are both above the limited values. While oil saturation and horizontal fracture aperture have an important impact on the shape of foam displacement front, foam system tends to avoid the pay zone with high oil saturation and percolates preferably into the horizontal fractures. High oil saturation leads to the collapse of foam displacement front and transfers it into surfactant flooding. The comparison of simulation works shows that both foam displacement velocity and front shape are closely related with injection pressure and injection cycles. With longer alternating period, the foam flooding front could propagate over a larger distance. The larger the injection pressure is, the more uniform the displacement front is.

This work is using simulation tool to analyze the impact of geological properties, foam system and injection parameters on the velocity and shape of foam displacement front. This is verified by field trials which provides some insight to the application of foam flooding at reservoir scale.
3D Close the Loop using Probabilistic Seismic Inversion for a Gas Field in Carnarvon Basin / Australia
Authors: Srivastava Shilpi , Goudswaard Jeroen , Busman Sito , Ugbo Justin
Published: November 2016

The study area is located in the Carnarvon Basin, offshore Western Australia. The paper discusses an approach for predicting the lateral variation of Net-to-Gross using 3D probabilistic seismic inversion. The goal is to define and understand the distribution of sands and shales on the basis of seismic reflection data. This modelling and inversion is supported by the good quality of seismic data. The seismic amplitude patterns indicate hydrocarbon presence and variation in properties like Net-to-Gross.

Qualitative 3D CtL ("Check the Loop") is used to highlight the mismatches between the forward modelled synthetic data generated from the model and the actual seismic. The possible causes of these mismatches are investigated and suggestions are made to improve the model in the key areas of mismatch. The Quantitative 3D CtL is used to further constrain the reservoir model by the seismic data. A 3D probabilistic seismic inversion for the main uncertain reservoir parameter using Shell's proprietary stochastic model-based elastic inversion algorithm is deployed.

After the 3D CtL with the static reservoir model, reserves in both North and South blocks of the field were reduced, whereas the probabilistic inversion highlighted the presence of a high Net-to-Gross (NtG) channelized feature which facilitated an additional volume booking for the central block. These insights immediately impacted development decisions.

This study underpins the benefits of seismically constrained reservoir modelling. The use of probabilistic inversion to map out geological features (like higher NtG channels) is a new insight in the applicability of this methodology.
Extracting More from Wireline Formation Testing: Better Permeability Estimation
Authors: Ramaswami S. R. , Cornelisse P. W. , Elshahawi H. , Hows M. , Dong C. L
Published: November 2016

The use of pressure transient data in the field of Formation Testing in efforts to describe productivity and permeability of reservoirs is considered mature technology, particularly when applied to data collected through production testing. The extension of this technique to data obtained using Wireline Formation Testers, where either a single probe or a straddle packer is used to propagate a pressure pulse into a reservoir, has been gaining momentum in the industry over the past decade, however the integration of these outputs with other measurements of rock and fluid data is not always straight forward. This paper presents different methods of using pressure transient data from Wireline Formation Testers such as quantitative permeability determination, identification of permeability discrepancies in homogenous clastic formations, upscaling of permeability in a complex stacked reservoir and comparison of Wireline Formation Tester and conventional well test derived permeabilities. Additionally, this paper highlights the challenges one faces while planning, acquiring and interpreting pressure transient data from Wireline Formation Testers, as well as the importance of real-time monitoring and control of data.
Current State and Future Trends of Wireline Formation Testing Downhole Fluid Analysis for Improved Reservoir Fluid Evaluation
Authors: Ramaswami S. R. , Cornelisse P. W. , Mooijer M. , Kim I. , Elshahawi H. , Dong C. L.
Published: November 2016

The introduction of downhole fluid analysis (DFA) two decades ago was a major addition to the wireline formation testing suite of measurements previously available in the industry, both in real-time to optimize the sampling operations and to provide additional fluid measurements as an integral component of integrated fluid property interpretations. The progression from basic measurements such as fluid resistivity to advanced optical analysis has paved the way for much improved definition of reservoir fluids, including the variation of fluids within reservoirs.

Downhole Fluid Analysis is a continuously evolving field, so we will begin this paper by looking back at the evolution and application of various types of sensors for operational real-time decision making as well as post-operational fluid evaluation. We will then highlight current capability gaps, focusing on the need for improved real-time contamination monitoring in some environments of interest and our desire to measure additional fluid properties and specific species concentrations.
A Theoretical Model for Dynamic Performance Prediction of Air-Foam Flooding in Heterogeneous Reservoirs
Authors: Yang Jun , Wang Xiangzeng , Wang Shubao , Gao Ruimin , Zhang Yizhong , Yang Yongchao , Zeng Fanhua
Published: November 2016

Air-foam flooding has already been pilot-tested and approved as a feasible and promising EOR method in tight oil reservoir. This study is to develop a simple but effective model to predict dynamic performance of air-foam flooding by considering main physical and chemical mechanisms in this process, such as gas channeling caused by mobility difference, flue gas driving and instability of foam.

According to the instability of foam, a new model is proposed to estimate recovery factor, which separates foam flooding status into three areas, including gas, water and foam area. Prediction of breakthrough time is critical for this model, which is estimated according to relation between area being swept and area to be swept by cycle of injected slug. Once the breakthrough time of gas and surfactant solution are estimated, dynamic performance of every stage during air-foam flooding is predictable. Relation between recovery factor and production time or PV can be predicted, if essential reservoir, fluid and operational parameters are provided.

Relative numerical simulation studies on homogeneous case and heterogeneous case are both introduced to validate proposed model. Results of comparison suggest this model is highly consistent with the numerical simulation results. The most extreme difference in recovery factor after ten years between proposed method and simulation is less than 6.2%, which is less than 2.5% in most case. Meanwhile, this model requires much less input data than numerical simulation for dynamic performance prediction, which makes it a really convenient tool to evaluate potential of an air-foam flooding project. Sensitivity analysis is introduced to study effects of variation in parameters on the performance of air-foam flooding project, including fluid injection rate, slug size, slug proportion and reservoir heterogeneity. The higher liquid ratio is injected in each slug, the better recovery factor is obtained. However, there isn't much difference once liquid ratio is higher than 50%. Recovery factor increases with higher fluid injection rate. Meanwhile, the increasing rate of recovery factor drops as fluid injection rate increases. Also, optimum slug size exists which means any slug size being higher or lower this value would result in lower recovery factor. These conclusions can help get optimized operational parameters once economic data are settled.

This proposed model considered major mechanisms in air-foam flooding and related reservoir, fluid and operational parameters, and provided a fast approach to predict dynamic performance of air-foam flooding and can be used as a tool to optimize the operational parameters. The core idea of this method, such as the estimation of breakthrough time, also provides a new approach to estimate the performance of other immiscible flooding method.
Production Diagnostic Analysis and Optimisation in Complex High GOR Horizontal Oil Producer
Authors: Kyi Ko Ko , Amin M Farid B M , Alam Bambang Noor , Salleh N Hajjar , Yaakob A Afiq , Wa Wee Wei , Haddad Sammy , Johan Zailily , Wijoseno Danny Aryo , Devan Thesigan
Published: November 2016

Horizontal wells have been an important development option for oil production due to the increased exposure to the hydrocarbon bearing interval in the long open section. Nevertheless, there are several typical complications associated with the horizontal well production. Firstly, the barefoot completion often collapses after certain period of production and to prevent that, a slotted liner is installed across the open-hole section to provide required mechanical support and improve the wellbore stability. Next, the permeability distribution can be in great contrast from heel to toe and this necessitates the installation of an inflow control device (ICD) to avoid premature gas or water breakthrough that can easily kill the oil production. All the aforementioned completions, while helping to optimise the oil production, can complicate further the flow regime in the horizontal section and make production monitoring very difficult. The questions like phase stratification, flow behind slotted liner and production source for fluid entering ICD need to be answered for accurate production diagnostics in such horizontal completions.

This paper presents successful production diagnostic work performed in a problematic and complex long horizontal oil well, completed with both slotted liner and ICD. The well has been suffering from increasing GOR three weeks into production in year 2012 and was produced with the lowest choke size since then and eventually shut off to avoid excessive gas production. The source of the gas needed to be identified to perform gas shut-off. The production diagnostic work started with thorough clean-out of the long horizontal slotted liner and ICD sections via active coil tubing. The clean-out was proven to be efficient and the well was successfully beaned up to high oil production rate for subsequent flow profile diagnostics. The complex flow regime in this complicated horizontal completion was well identified by the multi-spinner, multi probe production logging (PL) tool deployed using the active coil tubing.

The production log interpretation, the historical production plot and the surface well test results were integrated and provided the required information to determine the forward production strategy in this horizontal oil producer. The planning and the implementation of active coil tubing cleaning and multi-spinner, multi probe PL, as well as lessons learned and best practices throughout this production diagnostic work, will be discussed.
Quantifying Carbonate Heterogeneities that Impact Flow in Reservoirs: Lessons Learned from the Central Luconia Gas Fields, Malaysia
Authors: Warrlich G. M. , Ryba A. , Adams E. , Tam T. , Chiew E. C. , Angelatos M. , Soo D. K. , Lojikim Chrissie
Published: November 2016

Extended Abstract

Carbonate fields in Central Luconia have been delivering gas for about 30 years and petroleum engineers have been collecting large amounts of static and dynamic data by exploring, appraising and producing these Miocene platforms hosting the gas. The knowledge acquired is presently used to optimize existing field recovery, develop new fields without production data and reduce geohazards for drilling operations. It also provides an outstanding data set that can be extrapolated to understand the role of reservoir heterogeneities and hydrocarbon properties on production behavior and recovery in similar fields with less data outside Luconia.