Formation Evaluation

Specific surface area s is one of the most important and effective geometrical parameters in defining and interpreting s petrophysical relationships, textural framework, and fluid-solid interactions in porous media. It is defined as the interstitial surface area of the pores and pore channels for each unit of bulk volume, grain volume, or pore volume, or for a unit of Ž. Ž. weight of a material. Variations in the specific surface area s and mean grain size G influence the physical parameters p s. limestone, and marl were also obtained. The rocks in both reservoirs are generally characterized by fine-to medium grain size and high values of s .

The paper presents a numerical algorithm that performs accurate lithology corrections for thermal (CNL/TNPH, CNL/NPHI) and epithermal (SNP) neutron logs, in the whole range of porosities normally encountered in practice. It is known that neutron logs respond not only to a formation’s true porosity, but, to some extent, also to its lithology (the so-called "matrix effect"). Because the matrix effect is nonlinear and varies with true porosity, which is unknown beforehand, an iterative process is needed in order to carry out proper lithology corrections and obtain formation's porosity. The relationships between measured neutron porosity and true porosity for the common reservoir lithologies (sandstones, limestones and dolomites), at different formation water salinities, are approximable via suitable regression polynomials. Nonlinear neutron responses thus expressed are combined with the responses of density and sonic velocity logs, together with the volumetric unity constraint, into a system which is solved using a Newton-Raphson root-finding routine. The algorithm, implemented as a set of Matlab™ codes, provides optimal petrophysical models for the interpretation of neutron-density-sonic log suites and is easily adaptable in order to include additional linear or nonlinear log response equations. A case study regarding its applicability is also presented in the paper.

The identification of fluid contacts (gas–water contact—GWC, oil–water contact—OWC and gas–oil contact—GOC) is essential for field reserve estimates and field development and, also, for detailed formation evaluation. For the accurate calculation of some petrophysical parameters, such as porosity, the reservoir interval has to be zoned by fluid type, to account for differences in fluid saturations and fluid properties (e.g., hydrogen index, density, sonic transit time) in the various intervals: gas cap, oil column and aquifer zone. The fluid contacts may vary over a reservoir either because of faults, semipermeable barriers, rock quality variations / reservoir heterogeneity, hydrocarbon-filling history or a hydrodynamic activity. Horizontal contacts are typically taken into consideration, although irregular or tilted contacts occur in some reservoirs. The methods used for determining the fluid contacts include fluid sampling, water and hydrocarbons saturation estimation from geophysical well logs, analyses of conventional or sidewall cores, and formation pressure measurements. The pressure profiles obtained with various formation testing tools over reservoir intervals are, frequently, the primary source of data for defining the fluid contacts. When good quality pressure data can be collected, the fluid contacts can be determined by identifying the depths at which the pressure gradients (pressure versus depth trends) change. This study addresses some issues related to the identification of GWC for two gas fields of Early Pliocene age (Dacian stage), belonging to the biogenic hydrocarbon system of western Black Sea basin-Romanian continental shelf. We show that the identification of these contacts based exclusively on pressure gradients analysis is uncertain or may be inaccurate. The pressure gradients approach should be checked against the results of the conventional interpretation of geophysical well logs (e.g. changes in the computed fluid saturations as a function of depth) and, if available, the results of nuclear magnetic resonance (NMR) log investigations, which are able to indicate the intervals with clay-bound water, capillary-bound water and movable fluids.

Multidrug resistance (MDR) and extensive drug resistance (XDR) Proteus mirabilis are great threat to public health. Along with the drug resistance the biofilm forming capacity of these bacteria further complicate the treatment of infections caused by it. Furthermore, emergence of multidrug resistant Proteus mirabilis is increasing day by day. This study analyzed the relationship between antibiotic resistance and biofilm formation among the isolated Proteus mirabilis. It was a cross-sectional study over a period of one year from July 2019 to June 2020 at Dhaka Medical College Hospital. In this study we found that biofilm producing Proteus mirabilis were more antibiotic resistant than non-biofilm producing Proteus mirabilis. The biofilm formation was

For many years, it has been common practice to use tortuosity and cementation parameters as pre-established values. Nevertheless, is the importance of these parameters really understood? Do we know the effect on water saturation calculations of these parameters? Over the years and having worked Petrophysics for different environments and variable data sets, have notice how careless or easy selected these parameters are determined. Many times based on the first set of wells of the field or just by analogy. Interesting was to find a series of technical papers and studies regarding this topic and how a variety of techniques and values are available. This paper will review the determinations of these parameters and research their effect on water saturation calculations.

The dielectric constant of a material affects the way in which electromagnetic wave passes through it. Since the dielectric constants of oil and water are different, the behaviour of electromagnetic waves in reservoir rocks is of interest. Based on dielectric measurements, two classes of tools currently exist viz.: very high, and low frequency tool. They all use small antenna arrays to send electromagnetic waves through the
formation. Traditionally, the measurement of the conductivity or resistivity of a formation has been one of the main surveys performed in a borehole, primarily to determine water saturation. However, a second electrical characteristic of the formation can be determined – the dielectric permittivity. Dielectric devices can be used to determine formation saturation from data dependent on the dielectric permittivity. The basic measurements are of propagation time and attenuation of an electromagnetic wave as it passes through a specific interval of formation. As the propagation time in water is higher than in hydrocarbons or minerals, the measurement is primarily affected by the water-filled pore space of rocks. This is in contrast to the nuclear-porosity tools affected
by the total porosity. In addition, for a wide range of salinities, the propagation time in water is practically constant and so saturation estimations can be made without prior
knowledge of the resistivity of the formation water. When other open-hole log data are available, it is possible to distinguish between oil, gas, and water with unknown changing
water salinity. There are errors associated with conventional porosity tools. The dielectric dispersion logging tool is a relatively new tool that overcomes major problems of preexisting logs. The tool uses electromagnetic wave to detect water-filled porosity.

Formation evaluation is a very important stage in prospecting for reservoir characterization and hydrocarbon bearing zone identification. The study has been carried out by qualitative and quantitative analysis. The logging data studied comprises of gamma ray, dual induction micro spherical focused log, borehole compensated sonic log, spectral density dual spaced neutron log. The gamma ray log is used to determine lithology, reservoir and non reservoir rocks, facies and depositional environment. Dual induction micro spherical focused log calculates the resistivity of the flushed zone as well as medium and deep resistivity of the invaded and uninvaded zone. Borehole compensated sonic log measures travel time through the formation and thus porosity. It analyzes fluid rock type such as hydrocarbon or formation water. Porosity is calculated by both density and neutron log. Neutron log is used to identify hydrocarbon bearing zone as well as fluid type. In well#10, Habiganj Gas Field, the hydrocarbon bearing zone is found between the depth ranging1311m to1505m and gross thickness is 194m.In well#11, two gas zones upper gas sand(UGS) & lower gas sand (LGS), have been detected and they are prevailed in the depth ranging from 1373m to 1485m and 3076 m to 3081m .

Objectives: To provide recommendations to facilitate the management of severe thermal burns during the acute phase in adults and children.
Design: A committee of 20 experts was asked to produce recommendations in six fields of burn management, namely, (1) assessment, admission to specialised burns centres, and telemedicine; (2) haemodynamic management; (3) airway management and smoke inhalation; (4) anaesthesia and analgesia; (5) burn wound treatments; and (6) other treatments. At the start of the recommendation-
formulation process, a formal conflict-of-interest policy was developed and enforced throughout the process. The entire process was conducted independently of any industry funding. The experts drew up a list of questions that were formulated according to the PICO model (Population, Intervention, Comparison, and Outcomes). Two bibliography experts per field analysed the literature published from January 2000 onwards using predefined keywords according to PRISMA recommendations. The quality of data from the selected literature was assessed using GRADE1 methodology. Due to the current paucity of
sufficiently powered studies regarding hard outcomes (i.e. mortality), the recommendations are based on expert opinion.
Results: The SFAR guidelines panel generated 24 statements regarding the management of acute burn injuries in adults and children. After two scoring rounds and one amendment, strong agreement was reached for all recommendations.
Conclusion: Substantial agreement was reached among a large cohort of experts regarding numerous strong recommendations to optimise the management of acute burn injuries in adults and children.

We  propose  two  approaches  to  be  used  as  basic  ones in  solving  petrophysical  inversion  problem  –  automation  of  cluster
analysis and visualization by using polygons. We also propose organizational structure which allows integrating petrophysi-
cal and log interpretation expertise into a single complex.

The successful interpretation of open-hole well logging data relies on jointly using all
available petrophysical and geological information. This paper presents relevant case studies related to the integration of well logs with core measurements for exploration wells drilled in the Romanian continental shelf area of the Western Black Sea basin. The analyzed wells targeted gas-bearing sands and silts complexes of Early Pliocene (Dacian) age, developed in a deltaic to shallow marine sedimentary environment in two distinct fields. The wireline logging programs included conventional formation evaluation logs, pressure surveys, nuclear magnetic resonance, and borehole electrical imaging logs. The core dataset comprised routine and special measurements
(porosity, grain density, permeability, water saturation, and Archie parameters) carried out at quasi-reservoir confining pressure. The wireline logging suites were interpreted via a deterministic workflow, including core-derived interpretation parameters. Other core-derived parameters were used for constraining and validating the log interpretations. The results show that a problem related to the ambiguity of formation water resistivity can be overcome through resistivity–porosity dependencies constructed to include potential aquifer zones in the proximity of the Dacian gas-bearing reservoirs. This study also revealed and quantified uncertainties regarding the
estimation of gas–water contacts from formation pressure surveys, which can be mitigated by the confirmation or correction of pressure-derived fluid contacts via the well log interpretation results. Lastly, we identified a probable resistivity logs suppression effect related both to high contents of capillary-bound water and also to the limited resolution of electrical logging tools in the presence of sand-shale thin bedding or laminations.

FOR CITATIONS:
Salem, H.S. and  Chilingarian, G.V., 1999. "Determination of specific surface area and mean grain size from well-log data and their influence on the physical behavior of offshore reservoirs. Journal of Petroleum Science and Engineering (Elsevier), 22(4) February: 241-252. (A Scholarly Paper Published in International Journal).

ABSTRACT:
Specific surface area (ss) is one of the most important and effective geometrical parameters in defining and interpreting petrophysical relationships, textural framework, and fluid–solid interactions in porous media. It is defined as the interstitial surface area of the pores and pore channels for each unit of bulk volume, grain volume, or pore volume, or for a unit of weight of a material. Variations in the specific surface area (ss) and mean grain size (Gs) influence the physical parameters controlling electric current and hydraulic flow, as well as acoustic and seismic wave propagation and attenuation. In this study, the specific surface area per unit of pore volume (sp) and the mean grain size (Gs) were numerically determined from well-log data for 14 wells penetrating the Hibernia and Terra Nova reservoirs of the Jeanne d'Arc Basin (JDB), offshore Newfoundland, Canada. Both parameters (sp and Gs) were derived using the formation resistivity factor, porosity, and permeability. Mathematical and physical concepts of ss (including sp) and Gs were analyzed, and empirical equations linking sp and Gs with various petrophysical parameters were obtained. The lithological components (shale, sandstone, silt, limestone, and marl) were also obtained. The rocks in both reservoirs are generally characterized by fine- to medium grain size and high values of sp.

Еникеев Б.Н. (ОАО ЦГЭ, ЗАО ПАНГЕЯ) (Bne1 @ yandex.ru ; pst.h1.ru) Петрофизика (2004). Куда идем? Введение о петрофизике.
Казалось бы абсолютно дурацкий вопрос вынесен в заголовок!
Везде и каждый идет туда, куда может и хочет субъективно, сообразуя проблему баланса между аналогами дара первородства и чечевичной похлебкой. Тем не менее, вопрос имеет полное право на существование, поскольку часто время рас-ставляет все по своим местам (и километры расчетов по халтурным методикам и бесстыд-но разрекламированные претензии, имеющие в лучшем случае весьма сомнительное обоснование и загубленные месторождения и реальные и весьма редкие прорывы в пони-мании и приросте точности).
Претензии на уровни технологизации, достигнутые к настоящему времени в области пет-рофизического обоснования, вызывают невольное возражение (если не улыбку) у искушенного пользователя. Невольно вспоминаются слова классика: "мы ленивы и нелюбопытны.." Действительно, трудно соотнести более чем 60 летние усилия сотен петрофизиков из мно-гих стран с легкостью формально-бездумного кликания по меню мышкой выпускника ВУЗа по какому-либо "универсальному алгоритму". Причина того, что такое действо выглядит смешным (в отличии скажем от вызова табли-цы Excel, обеспечивающей построение графиков и подсчет сумм) кроется в фундамен-тальном различии строго определенных математических задач от задач петрофизических (в которых сама по себе задача соотнесения свойств объектов изучения, характеризуемых разным географическим положением, генезисом, возрастом не является тривиальной). Cложность петрофизических задач фундаментальна по той причине, что они, строго гово-ря, некорректны (нет строгих способов даже просто компактного и однозначного описа-ния состава и строения пород, не говоря уже о расчете по такому описанию их физических свойств). Именно невозможность корректного параметрического описания состава и строения и последующего вычисления физических свойств заставляет наиболее совестли-вых петрофизиков отказываться от выбора однозначного и единственного уравнения, свя-зывающего свойства пород с их компонентных составом (независимо от всех вышеупо-мянутых факторов, условно относимых нами к петротипу), и в лучшем случае говорить об области применимости тех или иных соотношений для конкретных литологических или фациальных типов. Таким образом, стоит задача одновременного выбора параметра, называемого нами петро-типом породы, описывающих его уравнений и коэффициентов. При этом в рамках петротипа можно предположить соблюдение особых "генетических" взаимосвязей (X-X), отражающих особенности его состава и эволюции, косвенно контро-лирующих вид взаимосвязей, связывающих аналоги измеряемых в скважинах физических свойств с фильтрационно-емкостными свойствами пород (X-Y). Таким образом, безотносительно к разговорам про пресловутый " гамбургский счет " , про-блема соизмеримости и осмысленности направлений развития иногда имеет право на су-ществование. Cобственно даже в физике одну и ту же задачу можно решать совершенно разными способами. При решении простой задачки из задачника все ответы должны сов-пасть. А вот при решении проблемы, когда из-за сложности общей постановки приходится решать что именно надо учесть и чем можно принебречь... По сложности проблематики нечто подобное происходит и с петрофизикой (мы используем классическое понимание этого слова как науки о физике горных пород, а не современное западное словоупотреб-ление petrophysics, порой как будто совершенно обессмысливающее само это понятие), что ясно для любого наблюдателя, отслеживающего текущее состояние дел в этой области знания.

The spatial distribution of petrophysical properties within the reservoirs is one of the most important factors in reservoir characterization. Flow units are the continuous body over a specific reservoir volume within which the geological and petrophysical properties are the same. Accordingly, an accurate prediction of flow units is a major task to achieve a reliable petrophysical description of a reservoir. The aim of this paper was core flow unit determination by using a new intelligent method. Flow units were determined and clustered at specific depths of reservoir by using a combination of artificial neural network (ANN) and a metaheuristic optimization algorithm method. At first, artificial neural network (ANN) was used to determine flow units from well log data. Then, imperialist competitive algorithm (ICA) was employed to obtain the optimal contribution of ANN for a better flow unit prediction and clustering. Available routine core and well log data from a well in one of the Iranian oil fields were used for this determination. The data preprocessing was applied for data normalization and data filtering before these approaches. The results showed that imperialist competitive algorithm (ICA), as a useful optimization method for reservoir characterization, had a better performance in flow zone index (FZI) clustering compared with the conventional K-means clustering method. The results also showed that ICA optimized the artificial neural network (ANN) and improved the disadvantages of gradient-based back propagation algorithm for a better flow unit determination.

Dans l’institut fédéral des hautes études en formation professionnelle (IFFP), la formation initiale des enseignants s’articule en 12 modules. Centrés sur le développement de la pratique réflexive, l’enseignement et les modes d’évaluation tentent d’être le plus interactifs possible. Mais avec l’apparition de formations à distance, comment garder une évaluation authentique ? Dans le but de répondre à cette question, nous testons depuis deux ans un dispositif d’ « e-valuation formatrice interactive ». Cette communication présentera dans un premier temps ce dispositif. Ensuite, sur la base des données récoltées auprès des participants, nous tenterons de comprendre dans quelle mesure l’enseignement à distance influence nos pratiques évaluatives.

Processing and interpretation of well logging data is a very complex process, in which mathematical algorithms, statistical and numerical methods are deeply involved. In order to solve the major problems studied by the well logging (determination of the lithology, and porosity for the geological formations, delimitation of the reservoir rocks, estimation of their saturations), the interpreter must take into account various disturbing influences such as the borehole effect, presence of shale into formations, influence of the adjacent beds etc. The Influence of the perturbing factors on measured values is hard to estimate and it must be approached by means of numeric or statistic algorithms.

The paper presents a numerical algorithm that performs accurate lithology corrections for thermal (CNL/TNPH, CNL/NPHI) and epithermal (SNP) neutron logs, in the whole range of porosities normally encountered in practice. It is known that neutron logs respond not only to a formation’s true porosity, but, to some extent, also to its lithology (the so-called "matrix effect"). Because the matrix effect is nonlinear and varies with true porosity, which is unknown beforehand, an iterative process is needed in order to carry out proper lithology corrections and obtain formation's porosity. The relationships between measured neutron porosity and true porosity for the common reservoir lithologies (sandstones, limestones and dolomites), at different formation water salinities, are approximable via suitable regression polynomials. Nonlinear neutron responses thus expressed are combined with the responses of density and sonic velocity logs, together with the volumetric unity constraint, into a system which is solved using a Newton-Raphson root finding routine. The algorithm, implemented as a set of Matlab™ codes, provides optimal petrophysical models for the interpretation of neutron-density-sonic log suites and is easily adaptable in order to include additional linear or nonlinear log response equations. A case study regarding its applicability is also presented in the paper.

FOR CITATIONS:
SALEM, H.S., 2000. Fluid-flow characterization of porous media (for the example of the Jeanne d'Arc Basin consolidated reservoirs). Energy Sources. 22(6), July: 557-572.

ABSTRACT:
Flow of fluids in porous media is a complicated process governed by several physical parameters and properties of the solid particles and fluid molecules, as well as the interactions between them. The Kozeny-Carman equation is one of the powerful equations that provides a better understanding of fluid flow. The equation can be
successfully applied to viscous flow and laminar flow through unconsolidated and consolidated porous media if some of its elements are known. One of these elements is the Kozeny-Carman coefficient (Kcc ), which has a specific influence on the
mechanism of fluid flow in porous media. In this study, Kcc , along with other cc parameters, was obtained numerically from well-log measurements for several wells penetrating the Canadian offshore Jeanne d’Arc Basin reservoirs, which consist of consolidated and heterogeneous rocks characterized by a complex network of pores and pore channels. It is shown that Kcc is not a constant but a variable depending on several physical parameters and lithological attributes and strongly related to fluid flow as well as to electric-current conduction in porous media. The Kozeny-Carman
coefficient, obtained as tortuosity (t ) times shape factor (Shf ) agrees well with that obtained as (t) times Archie cementation factor (m). This observation suggests that Shf and m are analogous to each other. An average value of 7.5 was obtained for Kcc , which can be used for similar media instead of the value of 5.0 that is inaccurately used for consolidated porous media. Also, an average value of 3.3 was obtained for (t) and an average value of 2.28 was obtained for Shf (analogous to m). Empirical equations linking Kcc and a variety of petrophysical parameters were also
obtained."

A digital twin can be said to be a virtual model of a physical body, living or non-living. By bridging the physical and the virtual model, data is transferred seamlessly allowing the virtual model to exist simultaneously with the physical body. It is, therefore, a digital replica of a possible and actual physical assets, systems, places, persons or devices. The success of any reservoir navigation service involves team effort from many disciplines that include engineering, well planning and design, geological study and a host of other fields. This usually results in lots of digital data from planning to execution, as well as a post-project stage where best practices are adopted for the next project. This paper will focus on showing how the reservoir navigation service earth model can be seen as a digital twin of a section of the earth and how advances have already been made in this light to aid in creating a perfect digital twin of the earth for geosteering purposes.

The Cambrian-Ordovician Gargaf Formation, in the central part of Sirte Basin, is considered as one of the main reservoirs for gas production as in Alestiqlal field. The petrophysical properties of the reservoir revealed very low matrix porosity and permeability and can be classified as tight reservoir. Auspiciously, presence of natural fractures considered as vital element for the reservoir production. Therefore, evaluation of such features become a mandatory for Sirte Oil Company (SOC) for optimum reservoir characterization and management. Considering that, image logs were acquired by SOC in most of the drilled wells in the field. Integrated borehole case study was conducted for 10 wells to evaluate both natural and drilling induced fractures as well as the sub-seismic faults from image logs. The results represented by fractures orientation and intensity are used to examine the relationship and impact of natural and drilling induced fractures on gas production. The identified present day maximum horizontal stress indicated that a certain trend of the natural fractures relative to the maximum horizontal stress is controlling the reservoir productivity performance of Gargaf reservoir in Alestiqlal Field.

Fracture zones are usually characterized by an increased fracture density and thus a higher secondary porosity. In the studied area (Potwar Basin, Northern Pakistan), the porosities derived from a neutron log and fracture apertures (obtained via-high­ resolution resistivity images) are very low, even if the resistivity images show a high fracture density cataclastic zone. This analysis refers to a tight carbonate reservoir located close to a major fault zone, with a high density of fractures that do not contribute to fluid flow due to their small apertures. The compressive, reverse faulting regime with active hanging walls led to the formation of the main hydrocarbon traps, these being laterally delimited by such faults. Borehole breakouts and drilling-­induced fractures were used for tectonic stress evaluation. The dominant minimum stress direction identified in the analyzed wells is WSW - ENE, normal to the direction of drilling-­induced fractures, as indicators of the maximum stress direction, which are oriented NNW - SSE. The orientation of drilling­-enhanced fractures confirms the maximum stress direction as determined via drilling-­induced fractures. The alignment of the major fault and the natural fractures, parallel to the minimum horizontal stress direction, suggests a compressional tectonic regime at the moment of their formation. The maximum tectonic stress, normal to the fractures direction, has contributed to apertures closure and secondary porosity reduction. This explains why in an area characterized by intense cataclasis, resulted from the fault proximity, porosity is less than 2% and fracture apertures are, generally, less than 0.5 mm. But the simultaneous presence of breakouts and drilling­-induced fractures in the same well is an indicator of a strike-­slip stress regime. One may conclude that a change in the tectonic stress regime took place, from a compressive to a strike-­slip one. The major fault, which initially had a compressive character (dominantly vertical movement), later became a strike­-slip one, with a dominantly horizontal component. Knowledge of the fractures' propagation direction with respect to maximum tectonic stress is extremely important for the potential design of horizontal wells. Experience has shown that production is highly correlated to fracture volume and connectivity in tight formations, implying the future successful economic development of this particular field lies in knowledge of the fracture propagation direction.

Formation evaluation and rock classification in organic-rich mudrocks are challenging due to heterogeneity and complex rock physics of these reservoirs. Previous rock classification methods for unconventional formations required extensive core data, and often neglected the importance of mechanical rock properties, which contribute to the ability to initiate and maintain hydraulic fractures. Furthermore, the rock classes obtained from well logs are not always consistent with geological facies. We introduce an integrated rock classification method which takes into account petrophysical, compositional, and mechanical properties of the fluid-bearing rocks as well as geological attributes. The objectives of this paper include (a) to estimate depth-by-depth petrophysical, compositional, and elastic properties using well logs and geological information, and X-ray mineral maps and (b) to provide rock classifications based on geological facies as well as petrophysical, compositional, and ela...

Mass transfer between fractures and matrix blocks is critical to oil recovery by waterflooding in fractured reservoirs. A scaling equation has been used for rate of oil recovery by spontaneous imbibition and presented their results as oil recovery vs. dimensionless time. Many conditions apply to this scaling equation, including identical core sample shapes and fluid viscosity ratios. Recent investigation by experiment of these two factors has resulted in a more generalized scaling equation for strongly water-wet systems with a general definition of characteristic length and a viscosity ratio term included in the definition of dimensionless time. In this paper, published data on oil recovery by imbibition have been analyzed and correlated through application of the new definition. These data sets were for different porous media, core dimensions, boundary conditions, and oil and water viscosities. All of the systems were strongly water-wet. The generalized correlation was fitted closely by an empirical mass transfer function with the new definition of dimensionless time as the only parameter. © 1997 Elsevier Science B.V.

Actualités en médecine d'urgence News in Emergency Medicine Rédacteurs associés : P.-G. Claret • H. Lefort • C. Rob • P. Le Conte • A. Gloaguen • V. Hamel • S. Goddet

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"Technological Support for Petrophysical Study of Interpretation (on the Example of Permeability Estimation)Normal access

Authors: M.A. Borisov and B.N. Еnikeev
Event name: Tyumen 2013 - New Geotechnology for the Old Oil Provinces
Session: Petrophysics, Geomechanics and Rock Physics
Publication date: 25 March 2013
Organisations: EAGE
Language: English
Info: Extended abstract,  PDF ( 1.2Mb )
Summary:
The report focuses on problems of petrophysical study of logging data interpretation. Authors concentrate on multialternative interpretation which requires petrophysical and technological support. "

"Petrophysical Knowledge and Ways of Formalization and Work with It in ModErn

Authors: B. Enikeev and O.A. Smirnov
Event name: Saint Petersburg 2006
Session: Data & Information Systems
Publication date: 16 October 2006
Organisations: SEG, EAGE
Language: Russian
Info: Extended abstract,  PDF ( 640Kb )

Summary:
Requirements for petrophysical knowledge organization, methods of their analysis, adjustment, and application based on different algorithms of applied statistics and nonlinear evaluation are considered. The organization and structure of petrophysical interrelations library, its’ algorithms and modes of operation are described in details"

Heterolithics (sand-shale laminae) occur because of high frequency alternation in flow energy of a depositional environment. Sand-shale laminae occurs in several depositional environments, e.g. tidal and lower shore-face. Occurrence in fluvial environments has been reported as well. Reservoirs occurring in these environments are plentiful in the Niger Delta. In heterolithic reservoirs, the sand laminae can be laterally extensive and thus can hold a significant resource volume. Unfortunately, these thinly laminated sand/shale sequences are often mistaken as low-resistivity wet sands despite their high hydrocarbon saturations. This happens because conventional electric logs and induction logs read low average resistivities across these beds. Laminated sand/shale sequences would naturally appear as homogeneous and anisotropic to conventional resistivity tools when the typical lamina thickness is finer than the tool's vertical resolution. This anisotropy can be resolved by multiple resistivity devices, like a 3-component resistivity tool. Also, Cores, imaging tools and other high-resolution logging tools could identify such laminated intervals.

Formation evaluation and rock classification in organic-rich mudrocks are challenging due to heterogeneity and complex rock physics of these reservoirs. Previous rock classification methods for unconventional formations required extensive core data, and often neglected the importance of mechanical rock properties, which contribute to the ability to initiate and maintain hydraulic fractures. Furthermore, the rock classes obtained from well logs are not always consistent with geological facies. We introduce an integrated rock classification method which takes into account petrophysical, compositional, and mechanical properties of the fluid-bearing rocks as well as geological attributes. The objectives of this paper include (a) to estimate depth-by-depth petrophysical, compositional, and elastic properties using well logs and geological information, and X-ray mineral maps and (b) to provide rock classifications based on geological facies as well as petrophysical, compositional, and elastic properties, which could enhance development of heterogeneous organic-rich shale formations. We jointly interpret well logs (i.e., triple-combo and elemental capture spectroscopy logs) to assess petrophysical and compositional properties of the formation. We then apply the Self-Consistent Approximation (SCA) method to calculate depth-by-depth effective elastic properties. Next, we classify rocks based on well-log-based estimates of total organic content (TOC), volumetric concentrations of minerals, and elastic properties using unsupervised artificial neural network. We independently classify rocks from the same well into microfacies and chemofacies by core description, petrographic analysis, and x-ray fluorescence (XRF) spectroscopy measurements. We successfully applied the method on a well in Eagle Ford formation located in McMullen County in south Texas. Results show a good agreement between the rock classes identified using well-log-based and corebased rock classification, as well as geological microfacies and chemofacies. The microfacies and chemofacies classification compliments the well-log-based rock classification by providing additional information about the texture and chemical composition of the formation which could influence their mechanical behavior. Hence, the rock classes can be improved based on both petrophysical and geologicalattributes, for selecting the best candidate zones for horizontal well placement.

Sequence stratigraphy and reservoir quality studies were carried out by integrating well logs from five wells, biofacies data, and 3-D seismic reflection data of an onshore field, Niger Delta. Nine stratigraphic bounding surfaces including five sequence boundaries (SBs) dated 13.1 through 21.8 Ma and four maximum flooding surfaces (MFSs) dated 15.9 through 20.7 Ma were delineated. Four depositional sequences were identified, with an observed upward increase in thickness. Three major stacking patterns (progradational, retrogradational, and aggradational) were delineated and interpreted as lowstand systems tract (LST), highstand systems tract (HST), and transgressive systems tract (TST) using their bounding surfaces. The main seismic facies units identified are variable amplitude facies, high-amplitude continuous facies, and chaotic facies, which were tied to corresponding well log responses. Reservoir lithofacies analysis revealed the presence of barrier bar, shoreface, tidally influenced channel, and fluvial distributary channel sands, within the three systems tracts, deposited in an overall shallow marine setting. Well correlation also showed considerable net sand reduction along depositional dip (southward) and across the strike (eastward) directions. Well log-derived petrophysical parameters such as porosity and permeability were evaluated within the context of the reservoir depositional facies. The best quality reservoirs were seen to be the TST barrier bar sands and tidally influenced channels with average porosity (ɸ) and permeability (K) values of 0.18 v/v and 542 mD and 0.24 v/v and 2215 mD respectively, while the HST shoreface and LST fluvial distributary channel sands possess average ɸ and K values of 0.16 v/v and 437 mD and 0.16 v/v and 309 mD respectively. The results establish that the major control on the differences in petrophysical properties is the primary depositional facies.

Physico-chemical and microbial status of 400 honey samples picked from 200 experienced apiculturists for laboratory elucidation based on indigenous processing techniques (IPTs) comprising (burning (B); crushing and straining (C&S); mashing and straining (M&S); boiling and straining (B&S)) reveals its quality defaults at various farm gates with significant variations (p<0.05) in pH, electrical conductivity (EC) and free acidity (FA) compared with total reducing sugar (TRS) and total viable microbial loads (TVMLs). The EC varied from (0.999 ± 0.001732 to 0.9997 ± 0.000577) µS/cm with the highest value from B&S IPT. The B; C&S and M&S IPTs resulted to lower FA values (8.10 ± 0.015, 9.50 ± 0.015 and 4.20 ± 0.030) me/kg respectively compared to B&S (10.00 ± 1.00-36.67 ± 0.58) me/kg. Greater variation in FA levels confirms the speculations of experts on its fluctuation tendency with honey. Indigenous B gave rise to both highest TRS (31%) and TVMLs (6.95 ± 0.044 cfu/ml). The entire IPTs ubiquitously impacted health threats on honey consumers emanating from microbial contamination. The C&S and M&S IPTs are proved as best honey processing techniques for large scale application at farmgates in Ghana because it conducts the highest counteractive pH to microbial invasions. Innovations on these improved methods could reduce consumer health risks by 90 to 95%.

Formation evaluation and rock classification in organic-rich mudrocks are challenging due to heterogeneity and complex rock physics of these reservoirs. Previous rock classification methods for unconventional formations required extensive core data, and often neglected the importance of mechanical rock properties, which contribute to the ability to initiate and maintain hydraulic fractures. Furthermore, the rock classes obtained from well logs are not always consistent with geological facies. We introduce an integrated rock classification method which takes into account petrophysical, compositional, and mechanical properties of the fluid-bearing rocks as well as geological attributes.

The objectives of this paper include (a) to estimate depth-by-depth petrophysical, compositional, and elastic properties using well logs and geological information, and X-ray mineral maps and (b) to provide rock classifications based on geological facies as well as petrophysical, compositional, and elastic properties, which could enhance development of heterogeneous organic-rich shale formations. We jointly interpret well logs (i.e., triple-combo and elemental capture spectroscopy logs) to assess petrophysical and compositional properties of the formation. We then apply the Self-Consistent Approximation (SCA) method to calculate depth-by-depth effective elastic properties. Next, we classify rocks based on well-log-based estimates of total organic content (TOC), volumetric concentrations of minerals, and elastic properties using unsupervised artificial neural network. We independently classify rocks from the same well into microfacies and chemofacies by core description, petrographic analysis, and x-ray fluorescence (XRF) spectroscopy measurements.

We successfully applied the method on a well in Eagle Ford formation located in McMullen County in south Texas. Results show a good agreement between the rock classes identified using well-log-based and corebased rock classification, as well as geological microfacies and chemofacies. The microfacies and chemofacies classification compliments the well-log-based rock classification by providing additional information about the texture and chemical composition of the formation which could influence their mechanical behavior. Hence, the rock classes can be improved based on both petrophysical and geologicalattributes, for selecting the best candidate zones for horizontal well placement.