Nomenclature

The table below outlines key nomenclature in Harmony Enterprise.

Variable Description
a

Nominal (instantaneous) decline rate

aelf

Decline rate at end of linear flow

af

Final nominal (instantaneous) decline rate

ai

Initial nominal (instantaneous) decline rate

alim Limiting nominal (instantaneous) decline rate
A

Area

Ac Cross-sectional area to flow
AD Areal extent of reservoir
Ao

Gas-oil pore size distribution index

ASRV

Area of stimulated reservoir volume

Aw

Oil-water pore size distribution index

AD Active directory
AOF Absolute open flow potential
APE Automatic parameter estimation
API American Petroleum Institute number
API Application programming interface
AWS Amazon web services
b

Decline exponent

ba,pss

Pseudo-steady state constant in the flow equation using material balance pseudo-time (gas)

bDpss

Dimensionless pseudo-steady state constant

bpss

Pseudo-steady state constant in the flow equation using material balance time (oil)

B

Formation volume factor

Bg

Formation volume factor for gas

Bgd Dry gas formation volume factor, ft3/scf, m3/m3
Bgi

Formation volume factor for gas at initial reservoir pressure and temperature

Bginj

Formation volume factor for injected gas

Bo

Formation volume factor for oil, bbl/stb, m3/m3

Bob

Formation volume factor for oil at bubble point

Boi

Formation volume factor for oil at initial reservoir pressure and temperature

Bw

Formation volume factor for water

Bwi

Formation volume factor for water at initial reservoir pressure and temperature

Bwinj

Formation volume factor for injected water

BOE Barrel of oil equivalent
c

Compressibility

cd

Relative change in pore volume due to desorption of gas

ce

Effective compressibility. For oil systems, includes oil, water, and formation compressibilities.
For gas systems, includes gas, water, and formation compressibilities.

cep

Relative change in pore volume due to formation and residual fluid expansion

cf

Formation / pore compressibility

cf,max

Formation compressibility at zero net overburden pressure

cfi

Initial formation compressibility

cg

Gas compressibility

g

Average gas compressibility

ci

Initial compressibility

cma

Matrix compressibility

co

Oil compressibility

ct

Total compressibility

c̅te

Total compressibility at average reservoir pressure including net gas compressibility due to water influx

cti

Total initial compressibility

cT

Isothermal compressibility

cT,w

Isothermal compressibility of water

cT,wf

Isothermal compressibility of gas-free water

cT,wg

Isothermal compressibility of gas-saturated water

cti

Total system compressibility at original reservoir pressure

cw

Water compressibility

cwip

Relative change in pore volume due to water influx and production

C

Transfer coefficient related to flow capacity of the formation

CCA Custom calculated attributes
CD

Storage coefficient

CDF Cumulative distribution function
CDI

Formation and connate water compressibility d rive index

CF

Casing flange (reference point for depth measurements)

CGR

Condensate gas ratio, bbl/MMscf, m3/103m3

Ca

Ash content (Langmuir isotherm)

CA

Reservoir shape factor

CaD

Dimensionless apparent wellbore storage

CAh

Shape factor for horizontal wells

CD

Dimensionless wellbore storage

Cg

Gas content

Cg,abdn/CO2 Gas content at abandonment pressure or CO2 concentration
Cgi

Initial gas content

CG

Input gas volume fraction

CL

Liquid input volume fraction

Cm

Matrix swelling coefficient

Co

Gas-oil entry capillary pressure

Cp

Mechanical compliance coefficient

CpD

Dimensionless storage pressure parameter

Cw

Oil-water entry capillary pressure.

Moisture content. (Langmuir isotherm)

Cal rate Calendar rate — does not account for time on production.
d

Effective decline rate

di

Initial effective decline rate

dlim

limiting effective decline rate

D

Turbulence factor

DD % Drawdown percentage
DDI

Depletion drive index

DLS Dominion land survey
DSN Data source name
E Young's modulus of elasticity
EC2 Elastic compute cloud by Amazon is a web service that can be used to create virtual machines running various operating systems on the cloud
EMS Entitlement Management System (EMS)
ENERDEQ® IHS's Energy Information Access & Integration Platform is an information access and integration platform that directly connects you to global energy data
Entity A well or scenario. Groups can include various entities (that is, wells and scenarios).
EOT End of tubing
EUR

Expected ultimate recovery

Eavg

Average error

Efw

Formation expansion factor

Eg

Gas expansion factor

Egi

Gas expansion factor at initial conditions

EL

In-situ liquid volume fraction (liquid holdup)

EL0

Horizontal liquid holdup

E

Inclined liquid holdup

Eo

Oil expansion factor

Et

Total expansion factor

f

Decimal fraction

fc

Compressibility modifier

F

Reservoir voidage from production

FDBC Fekete database connection tool
FMB Flowing material balance
Forecast Used to predict future production
FP Flowing pressure
FSD Forecast start date
FCD

Dimensionless fracture conductivity

gg

Geothermal gradient

G

Original gas-in-place

G Separator gas specific gravity (for fluid properties)
GHV

Gross heating value

GMB Gas material balance
GOR

Producing gas-oil ratio

GWR Gas water ratio
Gf

Free gas-in-place

Ginj

Cumulative gas injected

Gp

Cumulative gas production

Gpa

Additional gas production

Gp,n

Ultimate recoverable gas

Gpn

Cumulative gas production at time 'n'

Gr

Remaining gas

GT

Cumulative transferred gas volume in a connected reservoir

h

Net pay

hp

Perforated interval

HCPV Hydrocarbon pore volume
History matching

History matching is the process of evaluating your model against known production data (rate and pressure vs. time). For example, in an Analytical model, the inputs are measured sandface pressures and rates, along with a set of fixed parameters like permeability, initial reservoir pressure, saturations, etc. Since a model is just a complex equation that relates pressure to rate, then the measured rates can be applied to a given model in order to synthesize a set of sandface pressures (or vice versa). The history-matching process then consists of changing the model parameters until the synthesized data overlaps the measured data to a reasonable degree.

I

Incline rate

IAM Identity and access management (for Azure)
ID Inner diameter
IHDC Information hub direct connect — the Canadian-specific portion of IHS web services
IPR Inflow performance relationship
IWIP

Initial water-in-place

j

Time interval / timestep

J

Transfer coefficient

Jsat Productivity index. For more information, see Fetkovich-based fit.
k

Permeability

kabs

Absolute permeability

kaq

Aquifer permeability

ke

Effective roughness of pipe

kf

Fracture permeability

kg

Effective permeability of gas

kh

Horizontal permeability

ki

Initial permeability

kmatrix Matrix (outer zone) permeability
ko

Effective permeability of oil

kr

Pressure-dependent permeability ratio: kr = k / ki

kres

Reservoir permeability

krg

Gas-relative permeability

krgc

Gas-relative permeability at residual oil saturation

krgcw

Gas-relative permeability at connate water saturation

krgro

Gas-relative permeability at residual oil saturation

kro

Oil-relative permeability

krocw

Oil-relative permeability at connate water saturation

krog

Oil-relative permeability with respect to gas

krogc

Oil-relative permeability at critical gas saturation

krow

Oil-relative permeability with respect to water

krw

Water-relative permeability

krwgc

Water-relative permeability at critical gas saturation

krwro

Water-relative permeability at residual oil saturation

ksrv SRV (inner zone) permeability
kv

Vertical permeability

kw

Effective permeability of water

kx

Permeability in the x-direction

ky

Permeability in the y-direction

kz

Permeability in the z-direction

KB

Kelly bushing (reference point for depth measurements)

L

Horizontal wellbore length

LD

Dimensionless horizontal wellbore length

Le

Effective horizontal wellbore length

LRG Liquid rich gas
m

Slope from the flow equation using material balance time (oil)

ma

Slope from the flow equation using material balance pseudo-time (gas)

M Mobility ratio (analytical models) (water-drive typecurves)
MD

Measured depth (CF or KB)

MPP

Mid-point of perforations

Maq

Aquifer mobility

Mo

Molecular weight of stock tank liquid

Mres

Reservoir mobility

n

Moles of gas (ideal g as law equation)

nf

Number of fractures

ng

Gas exponent

nog

Oil-gas system exponent

now

Oil-water system exponent

nw

Water exponent

N

Original oil-in-place

NAD 27 North American Datum, created in 1927
NAD 83 North American Datum, modified in 1983
NGL Natural gas liquids
NTS National topographic (map numbering) system
Np

Cumulative oil production

Np,n

Ultimate recoverable oil

NVL

Liquid velocity number

ODBC Open database connectivity
OCIP Original condensate-in-place, Mstb, 103m3
OCIPSRV Original condensate-in-place in a stimulated region, Mstb, 103m3
OD Outer diameter
ODBC Open database compliant
OFIP Original fluid-in-place
OGIP

Original gas-in-place, MMscf, 106m3

OGIPA

Original adsorbed gas-in-place, MMscf, 106m3

OGIPF

Original free gas-in-place, MMscf, 106m3

OGIPSRV Original gas-in-place in a stimulated region, MMscf, 106m3
OMB Oil material balance
OOIP

Original oil-in-place, Mstb, 103m3

OOIPSRV Original oil-in-place in a stimulated region, Mstb, 103m3
OWIP Original water-in-place, Mstb, 103m3
OWIPSRV Original water-in-place in a stimulated region, Mstb, 103m3
Op Rate Operated rate — accounts for time on production.
p

Pressure

Average reservoir pressure

pab

Abandonment pressure

pair

Air pressure

paq

Aquifer pressure

paqi

Initial aquifer pressure

pbp

Bubble point pressure, psi(a), kPa(a)

pc

Critical pressure

(pce)go Gas-oil pore entry capillary pressure, psi(a), kPa(a)
(pce)ow Oil-water pore entry capillary pressure, psi(a), kPa(a)
pcgo

Gas-oil system capillary pressure, psi(a), kPa(a)

pcow

Oil-water system capillary pressure, psi(a), kPa(a)

pd

Desorption pressure

pdew Dew point pressure, psi(a), kPa(a)
pD

Dimensionless pressure

pDi

Dimensionless pressure integral

pDid

Dimensionless pressure integral derivative

pe

Bulk overburden pressure

pflow

Specified flowing pressure

pgrd

Overburden pressure gradient

pi

Initial reservoir pressure

pj

Pressure at time "j"

pL

Langmuir pressure

pmax

Maximum pressure

pmin

Minimum pressure

pn

Net overburden pressure

pni

Initial net overburden pressure

po

Oil pressure

pp

Pseudo-pressure

̅pp

Average pseudo-pressure

ppab

Abandonment pseudo-pressure

̅ppab

Average abandonment pseudo-pressure

ppi

Initial pseudo-pressure

ppwf

Wellbore flowing pseudo-pressure

pr

Reduced pressure

̅pR

Current reservoir pressure

psp

Separator pressure

psc

Pressure at standard conditions (14.65 psia, 101.0 kPa(a))

pw Water pressure
pwf Sandface flowing pressure
pwff

Sandface forecast pressure

pwh Wellhead flowing pressure
pε

Reservoir pressure at 50% matrix strain

P10 For each time interval, the P10 point is determined as the value for which 10% of the data points are higher. The production volume for each period is based on the calculated rate, and the cumulative production track is calculated by summing the calculated volumes. The P10 curve can be considered a highly optimistic prediction.
P50 For each time interval, the P50 point is determined as the value for which 50% of the data points are higher. The production volume for each period is based on the calculated rate, and the cumulative production track is calculated by summing the calculated volumes.
P90 For each time interval, the P90 point is determined as the value for which 90% of the data points are higher. The production volume for each period is based on the calculated rate, and the cumulative production track is calculated by summing the calculated volumes. A line is drawn through each P90 point to obtain the curve. The P90 curve is often considered as a conservative estimate of reserves.
PI

Productivity index

PVT

Pressure volume temperature

Pc

Capillary pressure
SPE recommends Pc (P being the secondary symbol for pressure) to denote capillary pressure, whereas pc is used to denote critical pressure.

POP Operating pressure
PRES Reservoir pressure
PSF Sandface pressure
q

Rate

Average rate

qab

Abandonment rate

qCRIT Critical flow rate
qD

Dimensionless rate

qDd

Dimensionless decline rate

qDde

Dimensionless decline rate accounting for total pool production

qDd, integral

Dimensionless rate integral

qelf

Rate at end of linear flow

qf

Final rate (abandonment rate)

qf = (number of wells) * (qGas / 6 +qOil);

qg

Instantaneous gas rate

(qg)f For FMB, URM, and Typecurve:
The final abandonment rate for gas
qginj

Injected gas rate

qi

Initial rate

qintegral

Rate integral

qj

Rate at time "j"

qMAX Maximum oil rate
qo

Instantaneous oil rate

(qo)f For FMB, URM, and Typecurve:
The final abandonment rate for oil
qOIL Oil rate
qOR Operating rate
qs

Gas flow rate from separator

qtot

Pool total production rate

qw

Instantaneous water rate

qwe

Rate of water influx

qwinj

Rate of water injection

Q

Cumulative production

QD

Dimensionless cumulative production

QDA

Area-based dimensionless cumulative production

QDd

Dimensionless cumulative decline production

Qf

Final cumulative production

Qg,dry

Cumulative surface gas production

Qg,wet

Cumulative well stream gas produced at the sandface

Qi

Initial cumulative production

Qm

Modified cumulative production

Qn

Normalized cumulative production

Qtot

Pool cumulative production

r

Radius

raq

Aquifer exterior radius

re

Reservoir effective radius

reD

Dimensionless effective radius

ro

Reservoir outer boundary radius (Water-drive Typecurves and Models)

Distance to observation well from active well, for cylindrical reservoirs

rw

Wellbore radius

rwa

Apparent wellbore radius

rwD

Dimensionless wellbore radius

rwe

Effective wellbore radius

R

Ideal gas law constant

RC Rate vs cumulative production
RDP Remote desktop protocol
RDS Relational Database Service created by Amazon
RF

Recovery factor

RR

Remaining recoverable

RT Rate vs time
Rp

Solution gas-oil ratio based on cumulative oil and gas production

Rs

Solution gas-oil ratio, scf/bbl, m3/m3

Rsb Solution gas-oil ratio at bubble point
Rsi

Initial solution gas-oil ratio

Rsr

Reduced solution gas-oil ratio

Rsw

Gas solubility in water

Rv Vaporized oil ratio, bbl/MMscf, m3/103m3
s

Skin

sd

Near-wellbore skin damage

s

Interporosity skin

sf

Fracture face skin

S

Salinity of water

Sandface C Sandface deliverability coefficient
Sandface/Wellhead n Turbulence factor
SDI

Segregation (gas cap) Drive Index

SI International system of units. For more information, see http://dictionary.reference.com/browse/si+units?s=t
SL

Surface losses

SPE Society of petroleum engineers
SQL Structured query language
SRV

Stimulated reservoir volume

Sg

Gas saturation

Sgc

Critical gas saturation

Sgi

Initial gas saturation

Sgn

Normalized gas saturation

Siw

Irreducible water saturation (Relative Permeability Correlations)

So

Oil saturation

Soi

Initial oil saturation

Son

Normalized oil saturation

Sor

Residual oil saturation

Sorg

Residual oil saturation to gas

Sorw

Residual oil saturation to water

Sw

Water saturation

Swc

Critical water saturation (capillary pressure)

Swc

Connate water saturation (relative permeability)

Swi

Initial water saturation

Swirr

Irreducible water saturation (capillary correlations)

Swn

Normalized water saturation

̅Sw

Average water saturation

t

Time

ta

Pseudo-time

tc

Material balance time

tca

Material balance pseudo-time

tcae

Total material balance pseudo-time for gas

tce

Total material balance pseudo-time for oil

tco

Length of the first time period in material balance time

tD

Dimensionless time

tDA

Area-based dimensionless time

tDd

Dimensionless decline time

tDde

Dimensionless decline time accounting for total pool production

tDxf

Dimensionless time based on fracture half-length (xf)

tDye

Dimensionless time based on reservoir width (Ye)

telf

Time at end of linear flow

tf

Time at start of forecast date

tflow

Specified flow time

tj

Time at the "jth" time period / timestep

tlim

Limiting time

tshut-in

Specified shut-in time

tstab

Time to stabilization

T

Temperature

TVD

True vertical depth (CF or KB)

TPC Tubing performance curve
Tc

Critical temperature

Tf

Formation temperature

Ti

Initial temperature

Tpp

Pour point temperature

Tr

Reduced temperature

Tsp

Separator temperature

Tsc

Temperature at standard conditions (60oF/15oC)

Tsp

Separator temperature

URM Unconventional reservoir module
vg

Gas velocity

vL

In-situ liquid velocity

vm

Mixture velocity

vsg

Superficial gas velocity

vsl

Superficial liquid velocity

V

Volume

VM Virtual machine
VR

Voidage replacement

VRR

Voidage replacement ratio

VACT Actual velocity
Vaq

Aquifer volume

VCRIT Critical velocity
VERO Erosional velocity
VHCP

Hydrocarbon pore volume

Vi

Initial volume

VL

Langmuir volume

VLi

Initial Langmuir volume

Vp

Pore volume

VR

Volatile oil ratio

Rock volume

Vsc

Volume at standard conditions

VT

Total volume

Vw

Wellbore volume

wf

Fracture width

WBS Well-based security
WDI

Water drive index

WGR Water gas ratio
WGS 84 World Geodetic System, modified in 1984
WOR

Water-oil ratio

We

Water encroachment from aquifer

Wei

Initial water encroachment from aquifer

Winj

Cumulative water injection

Wp

Cumulative water production

xe Reservoir length
xeD

Dimensionless reservoir length

xf

Fracture half-length

xi Half SRV width, or the distance from the fracture to the permeability boundary
xw

Active well location in the x-direction

y

Distance of investigation at time t

ye

Reservoir width

yw

Active well location in the y-direction

ye/yw

Ratio of reservoir width to well location in the y-direction

Z

Gas compressibility factor

Z**

Modified gas compressibility factor

Average gas compressibility factor

Zab

Compressibility factor at reservoir abandonment pressure

Zi

Compressibility factor at initial pressure and temperature

Zi**

Modified compressibility factor at initial pressure and temperature

zo

Location of observation well from top of zone (z-direction) for rectangular reservoirs

Zsc

Compressibility factor at standard conditions

zw

Well location in the z-direction (only applicable to horizontal wells)

α

Biot's coefficient (Geomechanical Reservoir Models - Dobrynin Correlation)

Separation factor / selectivity ratio (Langmuir Isotherm)

β

Square root of the anisotropic ratio kh/kv

βD

Ratio of total pool production to individual well production

γ Permeability modulus (Geomechanical Reservoir Models - Yilmaz & Nur Pressure-Dependent Permeability Correlation) Dimensionless correlation factor (Geomechanical Reservoir Models - Dobrynin Pressure-Dependent Permeability Correlation)

Euler's constant = 0.57721

γAPI

Specific gravity of liquid hydrocarbons / condensate in oAPI

γg

Specific gravity of gas

γg(psp)

Specific gravity of gas at separator pressure conditions

γo

Specific gravity of liquid hydrocarbons / condensate

γt

Recombined gas gravity

γw

Specific gravity of water

∆k

Change in permeability

∆pf

Change in pressure due to friction

∆pHH

Change in pressure due to hydrostatic head

∆Q

The difference between QPRODUCTION - QFORECAST (applies to the Monitor tab)

∆t

Forecast duration

∆Vd

Change in reservoir volume due to desorption of gas

∆Vep

Change in reservoir volume due to formation and residual fluid expansion

∆Vp

Reduction in hydrocarbon pore volume

∆Vw

Expansion of initial water volume

∆Vwip

Change in reservoir volume due to water influx and production

∆Xo

Location of observation well from active well in the x-direction, for rectangular reservoirs

∆Yo Location of observation well from active well in the y-direction, for rectangular reservoirs
∆Z

Change in elevation

ε

Tensile strain

εexp

Net strain between overburden stress effect and matrix shrinkage as measured experimentally

εL

Langmuir strain

θ

Angle of inclination

θr

[(T + 459.67) / 459.67] = relative temperature

λ

Interporosity flow coefficient

Pore size distribution index (Capillary Correlations - Brooks / Corey)

λgo Gas-oil pore size distribution index
λow Oil-water pore size distribution index
μ

Viscosity of primary fluid (gas / oil / water)

µ̅

Average viscosity

μaq

Aquifer viscosity

μg

Gas viscosity, cP, mPa.s

̅μg

Viscosity of gas at average pressure

μi

Viscosity at initial reservoir pressure

μL

Liquid viscosity

μm

Mixture viscosity

μNS

No-slip viscosity

μo

Oil viscosity, cP, mPa.s

μob

Oil viscosity at bubble point

μod

Viscosity of dead oil

μos

Viscosity of saturated oil

μres

Reservoir viscosity

μw

Water viscosity, cP, mPa.s

ν

Poisson's ratio

ξ

Reduced inverse viscosity

ρ

Density

ρa

Apparent density of surface gas

ρair

Air density

ρbs

Pseudo-liquid density at reservoir pressure and standard temperature

ρB

Bulk density

ρG

Gas density

ρL

Liquid density

ρm

Mixture density

ρmol

Molar density

ρNS

No-slip density

ρo

Oil density

ρob

Oil density at bubble point

ρoR

Oil density at reservoir conditions

ρpo

Pseudo-liquid density at standard conditions

ρst

Stock tank oil density

ρw

Water density

σ

Interfacial tension (capillary pressure)

σi

Effective horizontal stress at initial reservoir pressure

φ

Porosity

φi

Initial porosity

φt

Total porosity

Ψ

Pseudo-pressure

Ψ̅

Pseudo-pressure at average pressure

Ψi

Pseudo-pressure at initial reservoir pressure

Ψwf

Pseudo-pressure at sandface flowing pressure

ω

Storativity ratio