Drainage

Drainage adalah proses dimana fase non-wetting fluida mendesak fase wetting fluidanya. Dalam system water wet, kondisi ini ditemukan saat migrasi minyak ke reservoir. Drainage ditunjukkan dengan huruf g.

Imbibisi adalah proses dimana fase wetting fluida mendesak fase non-wetting fluidanya. Dalam system water wet, kondisi ini ditemukan saat produksi. Terdapat perbedaan kurva antara imbibisi dan drainage karena adanya Sor saat produksi. Perbedaan ini disebut histerisis. Imbibisi ditunjukkan dengan huruf h.

a dan b ialah water oil contact yang merupakan daerah gradasi (c) dimana nilai saturasi berubah-ubah pada masing-masing fasanya.

d ialah zona dimana hanya tersisa fasa non-wetting pada sistem water wet. Pada zona d, water tidak dapat mengalir karena telah mencapai Swirr.

e ialah zona free water level dimana hanya tersisa fasa wetting pada sistem water wet. Pada zona e, hidrocarbon tidak dapat mengalir karena telah mencapai Sor.

f ialah Swirr, yaitu saturasi water yang minimum dimana telah didesak oleh oil hingga tidak dapat mengalir kembali.

Pada titik c terdapat lengkungan karena terdapat proses imbibisi dan drainage yang penjelasannya sama seperti diatas. Hal tersebut dipengaruhi oleh besarnya tekanan kapiler, besarnya pore body,permeabilitas, dan pore throat.

Pundular : suatu komposisi pada batuan reservoir yang terisi fluida multi fasa (wetting dan non wetting phase) dimana saturasi fluida fasa wetting (misalnya : air) sedikit. Akibatnya pore body akan banyak terisi oleh fluida fasa nonwetting (misal: minyak) dan air akan terakumulasi di pore throat (ruang antar pori) dengan membentuk pola seperti cincin

Funicular : suatu kondisi yang berlawanan dengan pendular ring distribution, dimana saturasi minyak lebih sedikit dibandingkan saturasi air. Minyak berada di dalam pore body dalam jumlah kecil dan dikelilingi oleh air. Air terhubung antar suatu pori dengan pori lainnya.

P threshold terdapat saat titik b, yaitu saat pertama adanya WOC  ditemukan setelah dari FWL. P threshold adalah tekanan kapiler dimana pertama kali berubah nilai saturasi airnya.

http://lifetoact.blogspot.com/2010_05_01_archive.html

dual-porosity reservoir

1.  n.  [Well Testing] ID: 8027

A rock characterized by primary porosity from original deposition and secondary porosity from some other mechanism, and in which all flow to the well effectively occurs in one porosity system, and most of the fluid is stored in the other. Naturally fractured reservoirs and vugular carbonates are classified as dual-porosity reservoirs, as are layered reservoirs with extreme contrasts between high-permeabilityand low-

permeability layers.

http://www.glossary.oilfield.slb.com/Display.cfm?Term=dual-porosity%20reservoir

PorosityFrom Wikipedia, the free encyclopedia

This article needs additional citations for verification. Please help improve this article by adding citations to reliable sources. Unsourced material may be challenged and removed. (April 2008)

Porosity or void fraction is a measure of the void (i.e., "empty") spaces in a material, and is a fraction of

the volume of voids over the total volume, between 0–1, or as a percentage between 0–100%. The term is

used in multiple fields including pharmaceutics, ceramics, metallurgy, materials, manufacturing, earth

sciences and construction.

Contents

[hide]

1 Void fraction in two-phase flow 2 Porosity in earth sciences and construction o 2.1 Porosity and hydraulic conductivity o 2.2 Sorting and porosity o 2.3 Porosity of rocks o 2.4 Porosity of soil o 2.5 Types of geologic porosities

3 Measuring porosity 4 See also 5 References 6 Footnotes

[edit]Void fraction in two-phase flowIn gas-liquid two-phase flow, the void fraction is defined as the fraction of the flow-channel volume that is

occupied by the gas phase or, alternatively, as the fraction of the cross-sectional area of the channel that is

occupied by the gas phase.[1] Void fraction usually varies from location to location in the flow channel

(depending on the two-phase flow pattern). It fluctuates with time and its value is usually time averaged. In

separated (i.e., non-homogeneous) flow, it is related to volumetric flow rates of the gas and the liquid

phase, and to the ratio of the velocity of the two phases (called slip ratio).

[edit]Porosity in earth sciences and constructionUsed in geology, hydrogeology, soil science, and building science, the porosity of a porous medium (such

as rock or sediment) describes the fraction of void space in the material, where the void may contain, for

example, air or water. It is defined by the ratio:

where VV is the volume of void-space (such as fluids) and VT is the total or bulk volume of material,

including the solid and void components. Both the mathematical symbols   and   are

used to denote porosity.

Porosity is a fraction between 0 and 1, typically ranging from less than 0.01 for solid granite to more

than 0.5 for peat and clay. It may also be represented in percent terms by multiplying the fraction by

100.

The porosity of a rock, or sedimentary layer, is an important consideration when attempting to evaluate

the potential volume of water or hydrocarbons it may contain. Sedimentary porosity is a complicated

function of many factors, including but not limited to: rate of burial, depth of burial, the nature of

the connate fluids, the nature of overlying sediments (which may impede fluid expulsion). One

commonly used relationship between porosity and depth is given by the Athy (1930) equation:[2]

where   is the surface porosity,   is the compaction coefficient (m−1)

and   is depth (m).

A value for porosity can alternatively be calculated from the bulk density   and particle

density  :

Normal particle density is assumed to be approximately 2.65 g/cm3, although a better

estimation can be obtained by examining the lithology of the particles.

[edit]Porosity and hydraulic conductivityPorosity can be proportional to hydraulic conductivity; for two similar sandy aquifers, the one

with a higher porosity will typically have a higher hydraulic conductivity (more open area for

the flow of water), but there are many complications to this relationship. The principal

complication is that there is not a direct proportionality between porosity and hydraulic

conductivity but rather an inferred proportionality. There is a clear proportionality between

pore throat radii and hydraulic conductivity. Also, there tends to be a proportionality between

pore throat radii and pore volume. If the proportionality between pore throat radii and porosity

exists then a proportionality between porosity and hydraulic conductivity may exist. However,

as grain size and/or sorting decreases the proportionality between pore throat radii and

porosity begins to fail and therefore so does the proportionality between porosity and

hydraulic conductivity. For example: clays typically have very low hydraulic conductivity (due

to their small pore throat radii) but also have very high porosities (due to the structured nature

of clay minerals), which means clays can hold a large volume of water per volume of bulk

material, but they do not release water rapidly and therefore have low hydraulic conductivity.

[edit]Sorting and porosity

Effects of sorting on alluvial porosity

Well sorted (grains of approximately all one size) materials have higher porosity than similarly

sized poorly sorted materials (where smaller particles fill the gaps between larger particles).

The graphic illustrates how some smaller grains can effectively fill the pores (where all water

flow takes place), drastically reducing porosity and hydraulic conductivity, while only being a

small fraction of the total volume of the material. For tables of common porosity values

for earth materials, see the "further reading" section in the Hydrogeology article.

[edit]Porosity of rocksConsolidated rocks (e.g. sandstone, shale, granite or limestone) potentially have more

complex "dual" porosities, as compared with alluvial sediment. This can be split into

connected and unconnected porosity. Connected porosity is more easily measured through

the volume of gas or liquid that can flow into the rock, whereas fluids cannot access

unconnected pores.

[edit]Porosity of soilPorosity of surface soil typically decreases as particle size increases. This is due to soil

aggregate formation in finer textured surface soils when subject to soil biological processes.

Aggregation involves particulate adhesion and higher resistance to compaction. Typical bulk

density of sandy soil is between 1.5 and 1.7 g/cm³. This calculates to a porosity between 0.43

and 0.36. Typical bulk density of clay soil is between 1.1 and 1.3 g/cm³. This calculates to a

porosity between 0.58 and 0.51. This seems counterintuitive because clay soils are

termed heavy, implying lower porosity. Heavy apparently refers to a gravitational moisture

content effect in combination with terminology that harkens back to the relative force required

to pull a tillage implement through the clayey soil at field moisture content as compared to

sand.

Porosity of subsurface soil is lower than in surface soil due to compaction by gravity. Porosity

of 0.20 is considered normal for unsorted gravel size material at depths below the biomantle.

Porosity in finer material below the aggregating influence of pedogenesis can be expected to

approximate this value.

Soil porosity is complex. Traditional models regard porosity as continuous. This fails to

account for anomalous features and produces only approximate results. Furthermore it

cannot help model the influence of environmental factors which affect pore geometry. A

number of more complex models have been proposed,

including fractals, bubble theory, cracking theory, Boolean grain process, packed sphere, and

numerous other models. See also Characterisation of pore space in soil.

[edit]Types of geologic porositiesPrimary porosity

The main or original porosity system in a rock or unconfined alluvial deposit.

Secondary porosity

A subsequent or separate porosity system in a rock, often enhancing overall porosity of a rock.

This can be a result of chemical leeching of minerals or the generation of a fracture system. This

can replace the primary porosity or coexist with it (see dual porosity below).

Fracture porosity

This is porosity associated with a fracture system or faulting. This can create secondary porosity in

rocks that otherwise would not be reservoirs for hydrocarbons due to their primary porosity being

destroyed (for example due to depth of burial) or of a rock type not normally considered a reservoir

(for example igneous intrusions or metasediments).

Vuggy porosity

This is secondary porosity generated by dissolution of large features (such as macrofossils)

in carbonate rocks leaving large holes, vugs, or even caves.

Effective porosity (also called open porosity)

Refers to the fraction of the total volume in which fluid flow is effectively taking place and

includes Caternary and dead-end (as these pores cannot be flushed, but they can cause fluid

movement by release of pressure like gas expansion[3]) pores and excludes closed pores (or non-

connected cavities). This is very important for groundwater and petroleum flow, as well as for

solute transport.

Ineffective porosity (also called closed porosity)

Refers to the fraction of the total volume in fluids or gases are present but in which fluid flow can

not effectively take place and includes the closed pores. Understanding the morphology of the

porosity is thus very important for groundwater and petroleum flow.

Dual porosity

Refers to the conceptual idea that there are two overlapping reservoirs which interact. In fractured

rock aquifers, the rock mass and fractures are often simulated as being two overlapping but

distinct bodies. Delayed yield, and leaky aquifer flow solutions are both mathematically similar

solutions to that obtained for dual porosity; in all three cases water comes from two mathematically

different reservoirs (whether or not they are physically different).

Macro porosity

Refers to pores greater than 50 nm in diameter. Flow through macropores is described by bulk

diffusion.

Meso porosity

Refers to pores greater than 2 nm and less than 50 nm in diameter. Flow through mesopores is

described by Knudsen diffusion.

Micro porosity

Refers to pores smaller than 2 nm in diameter. Movement in micropores is by activated diffusion.

[edit]Measuring porosity

Optical method of measuring porosity:thin section under

gypsum plate shows porosity as purple color, contrasted with carbonate grains of other colors.Pleistocene eolianite from San Salvador Island, Bahamas. Scale bar 500 microns.

Several methods can be employed to measure

porosity:

Direct methods (determining the bulk

volume of the porous sample, and then

determining the volume of the skeletal

material with no pores (pore volume = total

volume − material volume).

Optical methods (e.g., determining the

area of the material versus the area of the

pores visible under the microscope). The

"areal" and "volumetric" porosities are

equal for porous media with random

structure.[4]

Computed tomography method

(using industrial CT scanning to create a

3D rendering of external and internal

geometry, including voids. Then

implementing a defect analysis utilizing

computer software)

Imbibition methods,[4] i.e., immersion of the

porous sample, under vacuum, in a fluid

that preferentially wets the pores.

Water saturation method (pore

volume = total volume of water −

volume of water left after soaking).

Water evaporation method (pore volume =

(weight of saturated sample − weight of

dried sample)/density of water)

Mercury intrusion porosimetry (several

non-mercury intrusion techniques have

been developed due to toxicological

concerns, and the fact that mercury tends

to form amalgams with several metals and

alloys).

Gas expansion method.[4] A sample of

known bulk volume is enclosed in a

container of known volume. It is connected

to another container with a known volume

which is evacuated (i.e., near vacuum

pressure). When a valve connecting the

two containers is opened, gas passes from

the first container to the second until a

uniform pressure distribution is attained.

Using ideal gas law, the volume of the

pores is calculated as

,

where

VV is the effective volume of the pores,

VT is the bulk volume of the sample,

Va is the volume of the container containing the sample,

Vb is the volume of the evacuated container,

P1 is the initial pressure in the initial pressure in volume Va and VV, and

P2 is final pressure present in the entire system.

The porosity follows straightforwardly by its proper definition

.

Note that this method assumes that gas communicates between the pores and the surrounding

volume. In practice, this means that the pores must not be closed cavities.

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Petroleum System (Sistem Minyak dan Gas Bumi)Faktor-faktor yang menjadi perhatian studi Petroleum System adalah batuan sumber (source rocks), pematangan (maturasi), reservoir, migrasi, timing, perangkap (trap), batuan penyekat (sealing rock) dan fracture gradient.

SOURCE ROCKSSource rocks adalah endapan sedimen yang mengandung bahan-bahan organik yang dapat menghasilan minyak dan gas bumi ketika endapan tersebut tertimbun dan terpanaskan.

Bahan-bahan organik yang terdapat didalam endapan sedimen selanjutnya dikenal dengan kerogen (dalam bahasa Yunani berarti penghasil lilin).

Terdapat empat tipe kerogen:

Tipe I: bahan- bahan organic kerogen Tipe I merupakan alga dari lingkungan pegendapan lacustrine dan lagoon.Tipe I ini dapat mengkasilkan minyak ringan (light oil) dengan kuallitas yang bagus serta mampu menghasilkan gas.

Tipe II: merupakan campuran material tumbuhan serta mikroorganisme laut. Tipe ini merupakan bahan utama minyak bumi serta gas.

Tipe III: Tanaman darat dalam endapan yang mengandung batu bara. Tipe ini umumnya menghasilkan gas dan sedikit minyak.

Tipe IV: bahan-bahan tanaman yang teroksidasi. Tipe ini tidak bisa menghasilkan minyak dan gas.

Kandungan kerogen dari suatu source rock dikenal dengan TOC (Total Organic Carbon), dimana standar minimal untuk 'keekonomisan' harus lebih besar dari 0.5%.

Implikasi penting dari pengetahuan tipe kerogen dari sebuah prospek adalah kita dapat memprediksikan

jenis hidrokarbon yang mungkin dihasilkan (minyak, gas, minyak & gas bahkan tidak ada migas).

MATURASIMaturasi adalah proses perubahan secara biologi, fisika, dan kimia dari kerogen menjadi minyak dan gas bumi.

Proses maturasi berawal sejak endapan sedimen yang kaya bahan organic terendapkan. Pada tahapan ini, terjadi reaksi pada temperatur rendah yang melibatkan bakteri anaerobic yang mereduksi oksigen, nitrogen dan belerang sehingga menghasilkan konsentrasi hidrokarbon.

Proses ini terus berlangsung sampai suhu batuan mencapai 50 derajat celcius. Selanjutnya, efek peningkatan temperatur menjadi sangat berpengaruh sejalan dengan tingkat reaksi dari bahan-bahan organik kerogen.

Karena temperatur terus mengingkat sejalan dengan bertambahnya kedalaman, efek pemanasan secara alamiah ditentukan oleh seberapa dalam batuan sumber tertimbun (gradien geothermal).

Gambar dibawah ini menunjukkan proporsi relatif dari minyak dan gas untuk kerogen tipe II, yang tertimbun di daerah dengan gradien geothermal sekitar 35 °C km -1 .

from OpenLearn - LearningSpace

Terlihat bahwa minyak bumi secara signifikan dapat

dihasilkan diatas temperature 50 °C atau pada kedalaman sekitar 1200m lalu terhenti pada suhu 180 derajat atau pada kedalaman 5200m. Sedangkan gas terbentuk secara signifikan sejalan dengan bertambahnya temperature/kedalaman.

Gas yang dihasilkan karena factor temperatur disebut dengan termogenic gas, sedangkan yang dihasilkan oleh aktivitas bakteri (suhu rendah, kedalaman dangkal <600m) disebut dengan biogenic gas.

Gambar di bawah ini merupakan contoh penampang kedalaman dari lapisan-lapisan batuan sumber, serta prediksi temperatur dengan cara menggunakan contoh kurva di atas. Dari penampang ini dapat diprediksikan apakah source tersebut berada dalam oil window, gas window, dll. Metoda ini dikenal dengan metoda Lopatin ( 1971). Terlihat jelas, metoda Lopatin hanya berdasarkan temperature dan mengabaikan efek reaksi kimia serta biologi.

Courtesy Fettes College

RESERVOIRAdalah batuan yang mampu menyimpan dan mengalirkan hidrokarbon. Dengan kata lain batuan tersebut harus memiliki porositas dan permeabilitas.

Jenis reservoir umumnya batu pasir dan batuan karbonat dengan porositas 15-30% (baik porositas primer maupun sekunder) serta permeabilitas minimum sekitar 1 mD (mili Darcy) untuk gas dan 10 mD untuk minyak ringan (light oil).

Berikut contoh-contoh reservoir berikut nilai porositas, permeabilitas, dll. (klik untuk memperbesar):

from OpenLearn - LearningSpace

MIGRASIMigrasi adalah proses trasportasi minyak dan gas dari batuan sumber menuju reservoir. Proses migrasi berawal dari migrasi primer (primary migration), yakni transportasi dari source rock ke reservoir secara langsung. Lalu diikuti oleh migrasi sekunder (secondary migration), yakni migrasi dalam batuan reservoir nya itu sendiri (dari reservoir bagian dalam ke reservoir bagian dangkal).

from OpenLearn - LearningSpace

Prinsip dasar identifikasi jalur-jalur migrasi hidrokarbon adalah dengan membuat peta reservoir. Kebalikannya dari air sungai di permukaan bumi, hidrokarbon akan melewati punggungan (bukit-bukit) dari morfologi reservoir. Daerah yang teraliri hidrokarbon disebut dengan drainage area (Analogi Daerah Aliran Sungai di permukan bumi). Jika perangkap tersebut telah terisi penuh (fill to spill) sampai spill point, maka hidrokarbon tersebut akan tumpah (spill) ke tempat yang lebih dangkal. Berikut contohnya:

Courtesy Sintef

TIMING

Waktu pengisian minyak dan gas bumi pada sebuah perangkap merupakan hal yang sangat penting. Karena kita menginginkan agar perangkap tersebut terbentuk sebelum migrasi, jika tidak, maka hidrokarbon telah terlanjur lewat sebelum perangkap tersebut terbentuk.

TRAPTerdapat macam-macam perangkap hidrokarbon: perangkap stratigrafi (D), perangkap struktur (A-C) dan kombinasi (E).

from OpenLearn - Learning Space

SEALSeal adalah system batuan penyekat yang bersifat tidak permeable seperti batulempung/mudstone, anhydrite dan garam.

FRACTURE GRADIENTDidalam evaluasi prospek, kurva fracture gradient diperlukan diantaranya untuk memprediksi sejauh mana overburden rocks mampu menahan minyak dan gas bumi. Semakin tebal suatu overburden, maka semakin banyak volume hydrocarbon yang mampu ‘ditahan’.

Gambar dibawah ini menunjukkan kurva fracture gradient dari gas, minyak dan air formasi dari sebuah lapangan. Berdasarkan kurva ini, jika kita memiliki sebuah perangkap dengan ketebalan overburden (c), maka ketebalan kolom gas maksimal yang mampu ditahan adalah (c-a), dan ketebalan kolom minyak

adalah (c-b), selebihnya hidrokarbon tersebut akan merembes keluar penyekat.