2. SUEZ UNIVERSITY
FACULTY OF PETROLEUM AND MINING ENGINEERING
GRADUATION PROJECT 2020
STUDY ON
SIMIAN FIELD
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The study includes the integration between different majors to construct a complete plan
about SIMIAN field. Majors that will be taken in consideration through this study are :
• Petroleum Geology and Exploration
• Drilling Engineering
• Well Logging
• Reservoir Engineering
• Well Testing
• Production Engineering
Petroleum Geology and Exploration
Geology is the science that comprises the study of the solid Earth and the processes by
which it is shaped and changed. Geology provides primary evidence for plate tectonics,
the history of life and evolution, and past climates.
Petroleum geology is the study of origin, occurrence, movement, accumulation, and
exploration of hydrocarbon fuels. It refers to the specific set of geological disciplines that
are applied to the search for hydrocarbons & oil exploration.
Subsurface geology is the combination of underground stratigraphy, structure and geologic
history. The obtained data are placed on maps to help to visualize and understand the
geologic conditions underground and so we can locate wildcat wells and extension wells.
The objective of subsurface petroleum geology is to find and develop oil and gas
reserves. This objective is best achieved by the use and integration of all the available
data and the correct application of these data.
The study will include the following
• Constructing structure contour maps (for both top and bottom of reservoir formation)
• Constructing Isopach maps
• Calculating the OGIP, using both the above two types of maps
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Drilling Engineering
Drilling is a process whereby a hole is bored using a drill bit to create a well for oil and
natural gas production. There are various kinds of oil wells with different functions:
• Exploration wells (or wildcat wells) are drilled for exploration purposes in new areas
• Appraisal wells are those drilled to assess the characteristics of a proven petroleum
reserve such as flow rate.
• Development or production wells are drilled for the production of oil or gas in fields
of proven economic and recoverable oil or gas reserves.
• Relief wells are drilled to stop the flow from a reservoir when a production well has
experienced a blowout.
• An injection well is drilled to enable petroleum engineers to inject steam, carbon
dioxide and other substances into an oil producing unit so as to maintain reservoir
pressure or to lower the viscosity of the oil, allowing it to flow into a nearby well.
The study will include the following
• Determine the number of casing strings needed for SEMIAN-3 and select the casing
setting depth for each one
• Design the typical program for selecting the weight and grade by using analytical
method for each casing in SIMIAN-3
• Design the cement program required
• Predicting the drilling problems that can be encountered during drilling SIMIAN-3
and how these problems can be treated in this field
• Design the drill string for each section in SIMIAN-3
• Design the well trajectory for proposed well by applying directional drilling
• Selecting the suitable rig type and its components
• Plotting some drilling parameters (ROP , RPM )
• Making a plot for trip and total (trip time ) VS depth
• Calculating the total drilling cost for SIMIAN-3
• A brief description about intelligent well completion
• A brief description about risk assessment in drilling
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Well Logging
Well logging, also known as borehole logging is the practice of making a detailed record
(a well log) of the geologic formations penetrated by a borehole. The log may be based
either on visual inspection of samples brought to the surface (geological logs) or on
physical measurements made by instruments lowered into the hole (geophysical logs.
Some types of geophysical well logs can be done during any phase of a well’s history:
drilling, completing, producing, or abandoning. Well logging is performed in boreholes
drilled for the oil and gas, groundwater, mineral and geothermal exploration, as well as
part of environmental and geotechnical studies.
The study will include the following
• Making qualitative and quantitative interpretation for (Resistivity, Neutron porosity,
Density, Gamma ray) logs
• Correlation between different wells
Reservoir Engineering
Reservoir engineering is the technology concerned with the prediction of the optimum
economic recovery of oil or gas from hydrocarbon-bearing reservoirs. It is an eclectic
technology requiring coordinated application of many disciplines: physics, chemistry,
mathematics, geology, and chemical engineering.
Originally, the role of reservoir engineering was exclusively that of counting oil and
natural gas reserves. The reserves are the amount of oil or gas that can be economically
recovered from the reservoir and are a measure of the wealth available to the owner and
operator. It is also necessary to know the reserves in order to make proper decisions
concerning the viability of downstream pipeline, refining, and marketing facilities that will
rely on the production as feed stocks. The scope of reservoir engineering has broadened
to include the analysis of optimum ways for recovering oil and natural gas, and the study
and implementation of enhanced recovery techniques for increasing the recovery above
that which can be expected from the use of conventional technology.
Reservoir engineers also play a central role in field development planning, recommending
appropriate and cost effective reservoir depletion schemes such as water flooding or
gas injection to maximize hydrocarbon recovery. Due to legislative changes in many
hydrocarbon producing countries, they are also involved in the design and implementation
of carbon sequestration projects in order to minimize the emission of greenhouse gases.
The study will include the following
• Identifying the reservoir driving mechanism and use the proper MBE for:
• Calculating IGIP
• Determine the water influx model (if exist)
• Run prediction for appropriate constrains
• MBAL software Material Balance Tool
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Well Testing
Well test interpretation is the process of obtaining information about a reservoir through
examining and analysing the pressure-transient response caused by a change in
production rate. This information is used to make reservoir management decisions. It
is important to note that the information obtained from well test interpretation may be
qualitative as well as quantitative. Identification of the presence and nature of a no
flow boundary or a down-dip aquifer is just as important as, if not more important than,
estimating the distance to the boundary
The study will include the following
• Determine the reservoir boundaries
• Determine the reservoir properties
• Determine the degree of heterogeneity in the reservoir
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Production Engineering
The role of a production engineer is to maximize oil and gas production in a cost-effective
manner. The reservoir supplies wellbore with crude oil or gas. The well provides a path
for the production fluid to flow from bottom hole to surface and offers a mean to control
the fluid production rate. The flow line leads the produced fluid to surface facilities.
Pumps and compressors are used to transport oil and gas through pipelines to sales
points. A complete oil or gas production system consists of a reservoir, well, flow line,
separators, pumps, and transportation pipelines
The study will include the following
• Draw the IPR for selected wells (current and future )
• Select the optimum tubing size
• Make total system analysis for selected wells
• Selecting the optimum gas processing method
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1.1 Introduction
Geology is the science that comprises the study of the solid Earth and the processes by
which it is shaped and changed. Geology provides primary evidence for plate tectonics,
the history of life and evolution, and past climates.
Petroleum geology is the study of origin, occurrence, movement, accumulation, and
exploration of hydrocarbon fuels. It refers to the specific set of geological disciplines that
are applied to the search for hydrocarbons & oil exploration.
Subsurface geology is the combination of underground stratigraphy, structure and geologic
history. The obtained data are placed on maps to help to visualize and understand the
geologic conditions underground and so we can locate wildcat wells and extension wells.
The objective of subsurface petroleum geology is to find and develop oil and gas
reserves. This objective is best achieved by the use and integration of all the available
data and the correct application of these data.
Data are obtained from:
- Geophysical surveys.
- Pressure and temperature surveys.
- The production history of the producing oil
and gas pools.
1.2 General Overview
1.2.1 Company Foundation
Burullus Gas Company
• Business Summary: Provides exploration,
drilling and production of natural gas.
• Country of Incorporation: Egypt
• Ownership Type: Government
• Established In: 1997
• Primary Sector: Oil and Gas
• Number of Employees: 650
• Concession area: cover the West Delta Deep
Marine (WDDM) Area offshore the Nile Delta.
1.2.2 Nile Delta Geology
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The Nile Delta is one of the classical deltas in the world, with a great history created by the
different civilizations. Beside its great history, the Nile Delta area is one of the major gas provinces
and one of the most promising areas for future petroleum exploration in north eastern Africa.
The Nile Delta is located in northern Egypt, where the Nile River spreads out and drains into the
Mediterranean Sea. It has an area of about 12,500 km2, very flat at the north and reaches up
to 18 m above sea level at Cairo. The Nile Delta is considered one of the world’s largest river
deltas. It covers approximately 230 km of Mediterranean coastline from Alexandria in the west
to Port Said in the east. The outer edges of the delta are eroding, and some coastal lakes such
as El Manzala and Burulls have experienced an increasing salinity levels as their connection to
the Mediterranean Sea increases.
The study area is part of the West Delta Deep Marine (WDDM) license which extends from 90
to 100 km offshore (250 - 1500 m water depth) of the present Nile Delta.
The WDDM license covers 8200 km2 on the north-western margin of the Nile delta cone.
Exploration activities at WDDM started in 1997. A series of successive successful exploration
and appraisal wells were drilled by British Gas (BG)-Egypt and Rashpetco. The main drilling
target was the Pliocene gas-bearing sands in slope canyon settings on the concession.
The studied area contains Simian and Sienna fields, located in WDDM in Simian/Sienna
development lease. The fields are approximately 120 kilometers offshore Idku, near Alexandria.
1.2.3 Simian Field
The Simian field was discovered by BG-Egypt. The first well, the Simian-l was drilled in 1999. Simian
is a combined stratigraphic-structural trap with dip-closure along the northern and southern margins.
The Simian field consists of a number of deep marine channels constrained within a
NNE-SSW trending initial channel valley cut. Simian channel system consists of two main
branches which merge to the north where the maximum width of the field is over 4.5 km.
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1.2.4 Stratigraphy
Late Pliocene to Early Pleistocene is represented by El Wastani Formation. It forms a
regressive sequence that unconformably overlies the Kafr El Sheikh Formation. The
depth of El Wastani Formation ranges from 900 m to 1000 m. The thickness appears
to be controlled by the Rosetta fault that was active in the top of the Kafr El-Sheikh
Formation due to the dipping of the formation to the NW and SW.
El Wastani Formation consists of clean and shaley Sandstones with interbedded
Claystones and Siltstone laminations
The depositional setting of the Plio-Pliestocene, Wastani Formation, is largely controlled
by both relative sea level changes and slope generated by major structural trends
(Rosetta and NDOA). The channel evolution through time is not very clearly defined
due to the lack of drilled wells, cores and stratigraphic heterogeneities of the reservoirs.
startigraphic column of the West Delta Deep Marine (WDDM) field (Raslan, 2002).
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1.2.5 STRATIGRAPHIC DIGEST: (WELL: SIMIAN Dh St3)
1.2.6 LITHOSTRATIGRAPHIC BRIEF: (WELL: SIMIAN Dh St3)
Interval from 1727 to 2062m
This interval consists mainly of CIaystone.
Claystone: Grey, occasionally pale grey, sub blocky to blocky, rarely sub flaky, rarely
sub-fissile, soft to moderately firm, generally clean, rarely slightly silty, trace of shell
fragments, trace disseminated pyrite, trace disseminated carbonaceous material, slightly
calcareous.
TOP SIMIAN CHANNEL @2062m MD (-2039.05m TVDSS)
Interval from 2062 m to 2129m
This interval consists mainly of Sand, Claystone and Siltstone streak.
Sand: Quartzose, colourless, occasionally pale orange, rarely light orange, rarely straw
yellow, transparent, occasionally translucent, medium to coarse grain, coarse grain in
part, rarely very coarse grain, subrounded to subangular, moderately to well sorted,
loose, consolidated in part to fine sand stone with argillaceous matrix and calcareous
cement, no visible porosity, no shows.
Claystone: Grey, occasionally pale grey, rarely dark grey, subblocky to blocky, soft
to moderately firm, silty to high silty in parts, trace of shell fragments, sandy, trace
disseminated pyrite, trace disseminated carbonaceous material, slightly calcareous.
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Siltstone: Pale grey, occasionally greenish grey, rarely light grey, sub blocky, soft to
moderately firm, occasionally grading to very fine sandstone glauconitic in parts highly
argillaceous, non calcareous.
Interval from 2129m to 2164m (F.T.D)
This interval consists mainly Sand with Claystone.
Sand: Quartzose, colourless, rarely light orange, transparent to translucent, fine to
medium grain, occasionally coarse grain, rarely very fine grain, loose, subrounded to
subangular, rarely rounded moderately to ill sorted, no visible porosIty, no shows.
Claystone: Grey, occasionally pale grey, rarely dark grey, subblocky to blocky, soft
to moderately firm, silty to high silty in parts, trace of shell fragments, sandy, trace
disseminated pyrite, trace disseminated carbonaceous material, slightly calcareous.
1.3 Geologic Maps
Geologic maps are used to:
1. Show the geologic history of the region.
2. Determine the kind of trap.
3. Estimate the initial hydrocarbon in place.
4. Predict the location of petroleum pools of the new geologic data uncovered.
5. Determine the location of source rock and the reservoir rock.
Contour lines:
• A contour line is a line that passes through points having the same elevation.
• Contour lines are characterized by the following:
• Contour lines are continuous.
• Contour lines are relatively parallel unless one of two conditions exist.
• A series of V-shape indicates a valley and the V’s point to higher elevation.
• A series U shape indicates a ridge. The U shapes will point to lower elevation.
• Evenly spaced lines indicate an area of uniform slope.
1.3.1 Types of Geologic Maps
• Surface maps: for surface anomalies.
• Subsurface maps: for subsurface anomalies.
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1.3.2 Types of Subsurface Maps
– Structure contour maps, and Cross sections
– Isofacies maps
– Paleogeologic and subcrop maps
– Hydrodynamic maps
– Geophysical maps
– Geochemical maps
– Internal property maps = Miscellaneous maps
– Isohydrocarbon map
– Isopach map
1.3.2.1 Structure Contour Maps and Cross Sections
Subsurface structures may be mapped on any formation boundary, unconformity, or
producing formation that can be identified and correlated by well data. Structure may be
shown by contour elevation maps or by cross-sections.
1.3.2.2 Isofacies Maps
There are several kinds of facies maps, but the most common type used in petroleum
geology are Lithofacies Maps, they can be divided into:
Lithofacies maps:
These maps distinguish the various lithologic types rather than formations.
Isolith maps:
These maps show the net thickness of certain lithology specially sandstone.
1.3.2.3 Paleo-Geologic and Sub-Crop Maps
Paleogeology may be defined as the science that treats the geology as it was during
various geologic periods.
A paleogeologic map: A map that shows the paleogeology of an ancient surface.
A subcrop map: A paleogeologic map in which the overlying formation is still present
where as a paleogeologic map shows the formation boundaries projected in part into the
area from which the overlying formation has been eroded.
1.3.2.4 Hydrodynamic Maps
These maps represent the relation between equipotential surface of oil and water in the
reservoir.
They represent the surface normal to which the movement of two fluids takes place.
It gives information about the direction of fluid movement, density of water and density of oil.
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1.3.2.5 Geophysical Maps
These maps depend on geophysical anomaly (such as local variations or irregularity in the
normal pattern) which after correction may be attributed to some geologic phenomena.
1.3.2.6 Geochemical Maps
These maps are used for mapping various kinds of chemical analysis of rocks and
their fluid contents. It may show the surface distribution of hydrocarbons where those
hydrocarbons are found at the surface in large amounts than normal indicating that there
is a seepage of oil or gas.
1.3.2.7 Miscellaneous Maps
These maps are prepared to show and illustrate specific phenomena. There are many
types of miscellaneous maps such as:
• Isoporosity maps: which show the lines of equal porosity in the potential reservoir
rock.
• Isobar maps: which show by contours the reservoir pressure in a pool.
• Isopotential maps: which show the initial or calculated daily rate production of
wells in a pool.
• Iso concentration maps: which show the concentration of salts in oil-field waters
by contours.
• Water encroachment maps: which show the position of wells from which water is
produced along with the oil.
• Isochore maps: which are lines joining points of equal vertical thickness. So
isochors maps record the vertical thickness of geological unit’s. These maps
illustrate such features as the depth of overburden above some deposits.
• Isovolume maps: which show the contours of equal porosity porosity-ft (net
thickness X porosity).
1.3.2.8 Isohydrocarbon Maps
Hydrocarbon potential = net pay thickness * porosity * hydrocarbon saturation
1.3.2.9 Isopach Maps
Isopach maps show by means of contour the varying thickness of the rock intervening
between two reference planes commonly bedding planes or surfaces of unconformity.
Isopach maps Offer a simple method of showing the distribution of a geological unit in
three-dimension (3D) thickness of individual formations of reservoir rocks of groups
of formations of intervals between unconformities or of intervals between a surface of
unconformity and a normal stratigraphic contactor formation boundary, may be mapped
in this manner. An Isochore map delineates the true vertical thickness, while isopach
illustrates the stratigraphic thickness.
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Isopach maps are used to:
• Determine the type of faulting and folding.
• The type of traps formation in regional studies.
• Development of a pool especially in showing the thickness of the pay formation.
Some Concepts
A. Pay determination
Several terms are used to describe the thickness of reservoir rock at a well. The
reservoir engineer must know what gross reservoir thickness, gross pay thickness and
net pay thickness are. Reservoir intervals that will contribute to reservoir production
are known as “pay”. Intervals that are accepted or eliminated from consideration as
pay are done so on the basis of their fluid saturation content, porosity, permeability,
and shaliness. The recognition of pay zones is an essential part of reservoir evaluation
both as a guide to perforation depths and in the computation of field reserves. The
terminology of pay determination is rather loose, but the criteria defined below are
consistent with common usage. In the example shown, a sandstone shale reservoir
interval is subdivided into a hierarchy of sub-intervals according to cut-offs applied to
logs and curves calculated from logs.
Schematic cross section of reservoir defines the thickness of reservoir rocks
B. Definitions:
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a) Gross reservoir interval: the unit between the top and base of the reservoir that
includes both reservoir and non-reservoir intervals.
b) Gross sandstone: (or limestone, dolomite, carbonate): the summed thickness of
intervals that are determined to be sandstone, usually determined by a Vsh. cut-off.
c) Net sandstone (or limestone, dolomite, carbonate): the summed thickness of gross
sandstone zones that have effective porosity and permeability, usually determined by a
porosity cut-off.
d) Gross pay thickness: the summed thickness of net sandstone zones that has
hydrocarbon saturation considered sufficient for economic production, usually determined
by a water-saturation cut-off.
e) Net pay thickness: the summed thickness of gross pay zones that should yield water-
free production, usually determined by an irreducible bulk volume water cut-off.
For vertical Well:
• RT: is the Rotary Table distance between the rotary
table to the end of well.
• KB: is the Kelly Bushing which is the distance
between rotary table & the mean seal level (MSL).
• MDss: is the measured depth subsea which is the
distance between mean sea level (MSL) to the end
of well (MDss=MD=KB).
For deviated Well (Directional):
• TVD: True Vertical Depth which is the vertical
distance from a point in the well to a point at the
rotary table.
• TVDss: true Vertical Depth Sub Sea which is the
vertical distance from a point in the well to the
mean seal level.
• MD: Measured Depth (always>TVD)
• ɸ: Angle of inclination which is angle of deviated
well with respect to its vertical origin
• A: Azimuth which is angle of deviated well with
respect to Magnetic North Pole
1.3.3 Methods of Drawing
There are two ways of drawing the maps:
1. The traditional method (freehand).
2. Computer Aided Design (CAD) using “SURFER” software for map drawing.
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Structural contour map construction procedures:
The conventional procedures in constructing the structural contour maps may be
summarized as:
1. Prepare a clear map for the field which contains subsurface faults and exact
locations of given wells throughout the field.
2. Label each well location with its corresponding value of formation encounter
(formation top depth value).
3. Connect all welIs with lines, taking into consideration that the lines don’t intersect,
and all possible lines are drawn.
4. Designate the required and/or the most suitable contour interval in depth units.
5. Divide the constructed lines with depths where for each line the intermediate values
between any two connected wells are covered. Take in consideration to denote
values only for the depth periods matching the designated contour interval and
to globalize these values in a way so that they could be connected together. For
example, if we select the contour interval to be IOO ft, then we should only denote
the values: 100ft, 200ft, 300ft... Etc.
6. Connect the denoted points, where each set of points having identical values are
connected by a line which called the contour line.
7. Copy the contour lines to a new copy of the map where they could be easily
recognized; the connected straight lines and numbers on the map may cause a
quite disturbance.
1.4 Required Maps
Maps of Formation
Using location map, Logging data and Mud logs for determining wells locations, and as
possible as some formation properties measured at each well
Well Name X Y Z (top) Z (base) Thickness (m)
Di 598752 1056777 -2071.75 -2229.75 158
Dp 598373.7 1060847 -2083 -2271.158 188.158
D(2) 599194.1 1059429 -2077.5 -2203.5 126
Dj 2 599194.1 1059429 -2073.25 -2150.55 77
Dm 595506 1046028 -2046.15 -2170.15 124
Dn 597993.8 1050228 -2014.4 -2206.4 192
D3 599191.4 1059429 -2066 -2230 164
Dhst 598279.4 1051718 -2039.05 -2164 124.95
Dq 593269 1047425 -2025 -2100 75
Ds 594417.5 1060793 -2142.9 -2222.89 79.99
Db 592966.3 1043380 -2030 -2092 62
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1.4.4 3D Surface Map
1.5 Volume In-Place Calculations
1.5.1 Methods of Calculation
There are several methods for calculating the Initial Hydrocarbon In-Place (IHIP),
Original Gas In-Place (OGIP), such as:
1. Volumetric analysis
2. Material Balance Analysis
3. Decline Curve Analysis
what matters here in Petroleum Geology section is the Volumetric Analysis for calculating
the OGIP, which is considered the most valuable method for estimating the OGIP in the
early life of the field.
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1.5.1.1 Volumetric Method
Volumetric Analysis is also known as the “geologist’s method” as it is based on cores,
analysis of wireline logs, and geological maps. Knowledge of the depositional environment,
the structural complexities, the trapping mechanism, and any fluid interaction is required to:
– Estimate the volume of subsurface rock that contains hydrocarbons. The volume is
calculated from the thickness of the rock containing oil or gas and the areal extent
of the accumulation.
– Determine a weighted average effective porosity.
– Determine a weighted average water saturation.
With these reservoir rock properties and utilizing the hydrocarbon fluid properties original
gas-in-place volumes can be calculated.
Accuracy of the volumetric method depends primarily on accuracy of data for:
1. Porosity.
2. Hydrocarbon saturation.
3. Net thickness.
4. Areal extent of the reservoir.
For GAS reservoirs, the mathematical expression for original gas in place (OGIP) by
volumetric method can be written as follows:
Bulk volume calculation methods
The bulk volume of the reservoir Vb
can be calculated using different methods but the
most common ones are:
• Trapezoidal Method
• Pyramidal Method
• Simpson’s method
1.5.1.1.1 Trapezoidal Method
This method requires that area ratio
Where
A = area enclosed by every two contour lines.
h = thickness between every two contour lines.
Vb
= bulk volume.
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1.5.1.1.2 Pyramidal Method
Bulk volume can be calculated as follows
This method requires that area ratio
1.5.1.1.3 Simpson’s Method
This method requires odd number of contour lines.
1.5.2 Calculation Procedure and Results
To guarantee high accuracy of calculations, formation bulk volume was calculated using
two methods
– Using formation top and bottom structural contour map
– Using Isopach Map
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1.5.2.1 Using Structural Contour Map
Calculation of the Bulk Volume from “SURFER” Program from Top Map
Total Volume (m^3)
Trapezoidal Method Simpson’s Method Simpson’s 3/8 Method
10290248698.73 10295394435.609 10289775275.632
Average Total Volume (m^3)
10291806140
Data from Logging and PVT:
Average Porosity Average Water Saturation Average Gross Thickness
0.28 0.3 124.6452727
Bgi (bbl/scf) (N/G) average Average Netpay Thickness
0.000734036 0.2206260967 27.5
Initial Gas In Place (scf)
3.813225964*(10)^12
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1.6 References
1. Prof. Dr S. E. Shalaby, ‘’Petroleum Geology’’, Faculty of Petroleum and Mining
Engineering, Suez University.
2. Prof. Dr S. E. Shalaby, ‘’An Introduction To Petroleum Engineering’’, Faculty of
Petroleum and Mining Engineering, Suez University.
3. Prof. Dr Hamed Khatab notes, Faculty of Petroleum and Mining Engineering,
Suez University.
4. Research Paper “ Seismic Imaging and Reservoir Architecture of Sub-Marine
Channel Systems Offshore West Nile Delta of Egypt”, Essam F Sharaf, Hamdy Seisa,
I.M. Korrat and Eslam Esmaiel.
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2.2. Well Summary:
The appraisal well Simian-3, operated by Rashid Petroleum Company (Rashpetco), was
drilled using the Atwood Oceanics semi-submersible ‘Eagle’ between 22nd June 2000
and 7th July 2000.
Located northeast of Alexandria, Simian-3 was sited in the eastern portion of the West
Delta Deep Marine concession, which lies offshore in the deep water (250-1500m) of
the present day Nile Delta. The license covers 8050 km2 on the north-western margin
of the Nile delta cone. The major tectonic features/controls on the license are the SW/
NE trending Rosetta Fault and the ENE-WSW trending NDOA anticline.
Simian is one of the major channel systems that make up the Mid-Pliocene submarine
channel complex mapped in the West Delta Deep Marine Concession. Simian is broadly
orientated NNE-SSW in direction and has two distinct branches that merge to the north.
Numerous, meandering channels are concentrated within the main branch.
The Simian-3 location was chosen to penetrate the central part of the Simian Channel
system approximately half-way between the successful Simian-1 and Simian-2 wells.
The objectives were to assess the reservoir facies distribution, petrophysical quality and
hydrocarbon charge by cuttings, cores and log analysis of the Simian Channel, as well
as to confirm the mapped continuity of the Simian Channel system through reservoir
pressures, fluid samples and fluid contacts.
A vertical hole was drilled to a TD of 2310mMD (-2286.5mTVDSS), successfully
penetrating the gas bearing Simian Channel unit within the Late Pliocene El Wastani
Formation, which comprised of clean and shaley Sandstones with interbedded
Claystones and Siltstone laminations. Top Simian reservoir was found at 2065.5mMD
(-2042.0mTVDSS), 11.0m high to prognosis.
A full Schlumberger openhole logging suite was made at final TD of the 8 ½” hole
over the Simian Channel. An intermediate DSI/TLD/APSGR run was made in the 12 ¼”
section. LWD was provided by Sperry Sun throughout the 12 ¼” (EWR/GR/MWD) and
8 ½” (EWR/GR/MWD) drilling phases.
Wireline MDT pressure measurements over the Simian Channel gave well defined gas
and water gradients of 0.232psi/m (0.163g/cc) and 1.432psi/m (1.007g/cc) respectively,
confirming connectivity between all the individual gas bearing beds with a continuous
119.0m gas column at this location. Pressures were also consistent with a single gas
reservoir between the current three Simian wells, though with a gas/water contact in
Simian-3 at 2184.5m MD (-2161.0m TVDSS), some 22m deeper than found in Simian-1
and 13.5m shallower than at the Simian-2 location. Top reservoir pressure was 3436psia
(9.73ppgEMW). Petrophysical analysis of the Simian gas leg gave a high case result
of 93.7m of net pay (78.7% net/gross) with average porosity 21.7% and average water
saturation 41.7%.
Gas samples were obtained in the Simian Channel with the MDT tool at 2078.4m and
2169.2m. A good water sample was also obtained in the Simian Channel.
No conventional cores were cut in this well, though 60 sidewall cores were shot in the
Simian reservoir and non-reservoir intervals with 47 recovered.
41. 37 Graduation Project 2020
Drilling Engineering
2.3. Introduction:
Drilling is a process whereby a hole is bored using a drill bit to create a well for oil and
natural gas production. There are various kinds of oil wells with different functions:
• Exploration wells (or wildcat wells) are drilled for exploration purposes in new areas.
The location of the exploration well is determined by geologists.
• Appraisal wells are those drilled to assess the characteristics of a proven petroleum
reserve such as flow rate.
• Development or production wells are drilled for the production of oil or gas in fields
of proven economic and recoverable oil or gas reserves.
• Relief wells are drilled to stop the flow from a reservoir when a production well has
experienced a blowout.
• An injection well is drilled to enable petroleum engineers to inject steam, carbon
dioxide and other substances into an oil producing unit so as to maintain reservoir
pressure or to lower the viscosity of the oil, allowing it to flow into a nearby well.
The process of drilling an oil and natural gas production well involves several
important steps:
• Boring - a drill bit and pipe are used to create a hole vertically into the
ground. Sometimes, drilling operations cannot be completed directly above
an oil or gas reservoir, for example, when reserves are situated under residential
areas. Fortunately, a process called directional drilling can be done to bore a well at
an angle. This process is done by boring a vertical well and then angling it towards
the reservoir.
• Circulation - drilling mud is circulated into the hole and back to the surface for
various functions including the removal of rock cuttings from the hole and the
maintenance of working temperatures and pressures.
• Casing - once the hole is at the desired depth, the well requires a cement casing
to prevent collapse.
• Completion - after a well has been cased, it needs to be readied for production. Small
holes called perforations are made in the portion of the casing which passed
through the production zone, to provide a path for the oil or gas to flow.
• Production - this is the phase of the well’s life where it actually produces oil and/
or gas.
• Abandonment - when a well has reached the end of its useful life (this is usually
determined by economics), it is plugged and abandoned to protect the surrounding
environment.
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2.4. Offshore Drilling Rigs:
An offshore rig is a large structure on or in water with facilities to drill wells, to extract
and process oil and natural gas, and to temporarily store product until it can be brought
to shore for refining and marketing. In many cases, the platform contains facilities to
house the workforce as well.
Offshore rigs are similar to land rigs but with several additional features to adapt them
to the marine environment. Those features include
• Heliport
• Living quarters
• Cranes
• Risers
The heliport, also known as the helipad, is a large deck area that is placed high and to
the side of offshore rigs. It is an important feature since helicopters are often the primary
means of transportation. The living quarters usually comprise bedrooms, a dining hall, a
recreation room, office space, and an infirmary. Escape boats are usually located near
the living quarters.
Cranes are used to move equipment and material from work boats onto the rig and to
shift the loads around on the rig. Most rigs have more than one crane to ensure that
all areas are accessible. A riser is used to extend the wellhead from the mudline to
the surface. On platforms and jackup rigs, the blowout preventers (BOPs) are mounted
above sea level. On floaters, the BOPs are mounted on the seafloor.
The various types of offshore rigs include barges, submersibles, platforms,
jackups, and floaters (the latter of which include semisubmersibles and drill
ships).
Barges
A barge rig is designed to work in shallow water (less than 20 ft deep). The rig is floated
to the drillsite, and the lower hull is sunk to rest on the sea bottom. The large surface
area of the lower hull keeps the rig from sinking into the soft mud and provides a stable
drilling platform.
Submersibles
A submersible rig is a barge that is designed to work in deeper water (to 50 ft deep). It
has extensions that allow it to raise its upper hull above the water level.
Platforms
Platforms use a jacket (a steel tubular framework anchored to the ocean bottom) to support
the surface production equipment, living quarters, and drilling rig. Multiple directional
wells are drilled from the platform by using a rig with a movable substructure. The rig is
positioned over preset wellheads by jacking across on skid beams. After all the wells
are drilled, the rig and quarters are removed from the platform. Smaller platforms use a
jackup rig to drill the wells.
43. 39 Graduation Project 2020
Drilling Engineering
Jackups
Jackups are similar to platforms except that the support legs are not permanently
attached to the seafloor. The weight of the rig is sufficient to keep it on location. The
rig’s legs can be jacked down to drill and jacked up to move to a new location. When
under tow, a flotation hull buoys the jackup. The derrick is cantilevered over the rear to
fit over preset risers if necessary.
Floaters
Offshore rigs that are not attached to or resting on the ocean bottom are called floaters.
These rigs can drill in water depths deeper than jackups or platforms can. They have
several special features to facilitate this:
• They are held on location by anchors or dynamic positioning.
• The drill string and riser are isolated from wave motion by motion compensators.
• The wellheads and BOPs are on the ocean bottom and are connected to the rig by
a riser to allow circulation of drilling mud.
• There are two categories of floaters: semisubmersibles and drill ships.
Semisubmersibles
Semisubmersibles (also called semis) are usually anchored in place. Although a few
semis are self-propelled, most require towing. Because floaters are subject to wave
motion, their drilling apparatus is located in the center where wave motion is minimal.
Semis are flooded to a drilling draft where the lower pontoons are below the active wave
base, thereby stabilizing the motion.
Drill ships
The drilling apparatus on a drill ship is mounted in the center of the ship over a moon
pool, which is a reinforced hole in the bottom of the ship through which the drill string is
raised and lowered. The ship can be turned into the oncoming wind or currents for better
stability, and it can operate in water too deep for anchors.
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Drilling Engineering
2.5. Bottom Hole Assembly:
A bottom hole assembly (BHA) is a component of a drilling rig. It is the lowest part of
the drill string, extending from the bit to the drill pipe. The assembly can consist of drill
collars, subs such as stabilizers, reamers, shocks, hole-openers, and the bit sub and bit.
The BHA design is based upon the requirements of having enough weight transfer to the
bit (WOB) to be able to drill and achieve a sufficient Rate of Penetration (ROP), giving
the Driller or Directional Driller directional control to drill as per the planned trajectory
and to also include whatever Logging While Drilling (LWD) / Measurement While Drilling
(MWD) tools for formation evaluation. As such BHA design can vary greatly from simple
vertical wells with little or no LWD requirements to complex directional wells which must
run multi-combo LWD suites.
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Prior to running a BHA most oilfield service providers have software to model the
BHA behaviour such as the maximum WOB achievable, the directional tendencies &
capabilities and even the natural harmonics of the assembly as to avoid vibration brought
about by exciting natural frequencies.
BHA configurations
There are three types of BHA configurations. These configurations addressed are
usually concerned with the use or layout of drill collars, heavy weight drill pipe and
standard drill pipe.
• Type 1, standard simple configuration, uses only drill pipe and drill collars. In this
instance the drill collars provide the necessary weight on the bit.
• Type 2, uses heavy weight drill pipe as a transition between the drill collars and the
drill pipe. Weight on bit is achieved by the drill collars.
• Type 3, uses the drill collars to achieve directional control. The heavy weight drill
pipe applies the weight on the bit. Such a layout promotes faster rig floor BHA
handling. It may also reduce the tendency for differential sticking.
In most cases the above three types of configurations usually apply to straight/vertical
wellbores at most low to medium angle wellbores. For high angle and horizontal wellbore
careful weight control of the BHA is a must. In this instance the weight may be applied
by running the drill pipe in compression in the high angle section. The high angle may
help to stabilize the drill pipe allowing it to carry some compression.
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Drilling Engineering
2.6. Casing:
Large-diameter pipe lowered into an open hole and cemented in place. The well designer
must design casing to withstand a variety of forces, such as collapse, burst, and tensile
failure, as well as chemically aggressive brines. Most casing joints are fabricated with
male threads on each end, and short-length casing couplings with female threads are
used to join the individual joints of casing together, or joints of casing may be fabricated
with male threads on one end and female threads on the other. Casing is run to protect
fresh water formations, isolate a zone of lost returns or isolate formations with significantly
different pressure gradients. The operation during which the casing is put into the
wellbore is commonly called “running pipe.” Casing is usually manufactured from plain
carbon steel that is heat-treated to varying strengths, but may be specially fabricated of
stainless steel, aluminum, titanium, fiberglass and other materials.
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2.7. Cement:
Well cementing is the process of introducing cement to the annular space between the
well-bore and casing or to the annular space between two successive casing strings.
Cementing Principle
• To support the vertical and radial loads applied to the casing
• Isolate porous formations from the producing zone formations
• Exclude unwanted sub-surface fluids from the producing interval
• Protect casing from corrosion
• Resist chemical deterioration of cement
• Confine abnormal pore pressure
• To increase the possibility to hit the target
Cement is introduced into the well by means of a cementing head. It helps
in pumping cement between the running of the top and bottom plugs.
The most important function of cementing is to achieve zonal isolation. Another purpose
of cementing is to achieve a good cement-to-pipe bond. Too low an effective confining
pressure may cause the cement to become ductile.
For cement, one thing to note is that there is no correlation between
the shear and compressive strength. Another fact to note is that cement strength ranges
between 1000 and 1800 psi, and for reservoir pressures > 1000 psi; this means that the
pipe cement bond will fail first. This would lead to the development of micro-annuli along
the pipe.
Cement Classes
A. 0–6000 ft used when special properties are not required.
B. 0–6000 ft used when conditions require moderate to high sulfate resistance
C. 0–6000 ft used when conditions require high early strength
D. 6000–10000 ft used under moderately high temperatures and pressures
E. 10000–14000 ft used under conditions of high temperatures and pressures
F. 10000–16000 ft used under conditions of extremely high temperatures and
pressures
G. 0–8000 ft can be used with accelerators and retarders to cover a wide range of
well depths and temperatures.
H. 0–8000 ft can be used with accelerators and retarders to cover a wide range of
well depths and temperatures.
I. 12000–16000 ft can be used under conditions of extremely high temperatures and
pressures or can be mixed with accelerators and retarders to cover a range of well
depth and temperatures.
49. 45 Graduation Project 2020
Drilling Engineering
Additives
There are 8 general categories of additives.
• Accelerators reduce setting time and increases the rate of compressive strength
build up.
• Retarders extend the setting time.
• Extenders lower the density
• Weighting Agents increase density.
• Dispersants reduce viscosity.
• Fluid loss control agents.
• Lost circulation control agents.
• Specialty agents.
2.8. Directional Drilling:
Directional drilling commences at the surface
as a vertical well. This drilling will commence
until the drill front is approximately 100 m
above the target. At this point, there is a
hydraulic motor attached between the drill
pipe and the drill bit. This motor can alter
the direction of the drill bit without affecting
the pipe that leads up to the surface.
Furthermore, once the well is being drilled at
a certain angle, many additional instruments
are placed down the hole to help navigate
and determine where the drill bit should go.
This information is then communicated to the surface and then to the motor, which will
control the direction of the bit.
Instead of conventional drilling, directional drilling opened up many new possibilities for
improving production and minimizing wastes by reaching target reservoirs. There are
three types of directional drilling, extended-reach drilling, horizontal drilling, and multiple
laterals off a single main well bore. The Next Figure shows different types of advanced
drilling technology.
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Directional program
A directional drilling program might be necessary if the target horizon is not accessible
from a location directly above it. This could be due to topographical obstacles (lakes or
mountains) or legal barriers (eg, protected land). The advantage of directional drilling
includes intersecting a liquid-bearing fracture at a more beneficial angle compared to a
vertical intersection. Moreover, directional drilling allows having multiple wells originating
at the same surface location and deflecting into different directions (angles) as they go
deeper. This enables tapping one resource from different positions (angles) or to explore
further into the underground. Multiple wells on a given drill pad also reduce the total costs
of drill site construction since only one access road is needed, the rig is skidded within
a short time and distance, only one disposal pit is needed, steam gathering pipe work
costs are lowered, and overall supply costs are reduced.
Planning a well that markedly deviates from vertical to reach its target reservoir is a
complex process. After determining the above-mentioned reservoir and casing depth in
the first step, the geometry of the well needs to be established. S-shaped or J-shaped
wells are mostly applied in the geothermal industry.
Directional Drilling Patterns
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2.9. Drilling Problems:
Sources of abnormal pressures in Nile Delta & Offshore Mediterranean
Basins
1. Compaction
Due to the clay-based marine sediments associated with turbodite sequences in the
Mediterranean Basin.
2. Tectonics
The Mediterranean Basin had been subjected to very active tectonics during Pliocene
and Miocene ages as following:
• Tectonic Stresses
• Faults and Fractures
3. High Sedimentation Rate
Due to rapid subsidence rate, beginning from the early Miocene and continuing to the
present day.
4. Thermal Mechanism
Due to hydrocarbon generation and clay dehydration
5. Pressure Communication along permeable faults and fractures
6. Sand / Shale Ratio
It is relatively high near the Top, Middle, West, and North West of the basin especially in
the Pleistocene and Pliocene formations.
Remedy: It is necessary to increase mud weight during drilling operations in the
abnormal pressure zones.
Hole Instability Problems
1. Mechanical Hole Instability
• Hole failure under tension due to mud loss of circulation through sands.
• Hole failure under compression due to kick or blow out while drilling through thick
permeable sands.
Remedy:
– Prevention of differential sticking through reducing the differential pressure (Pm –
Pf) to be 100 or 200 psi or 300 psi for over pressurized zones.
– Reducing the contact area through reducing the solids in the mud.
– The mud weight should be adjusted to overcome the pore pressure, and in the
same time to prevent the failure under tension in the weakest point below the
previous casing show.
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2. Chemical Hole Instability
The main composition of formations lithology in the basin is shale that make up over 80%
of thr drilled formations and causes more than 85% of the wellbore instability problems
like: Shale Sloughing & Swelling.
Remedy: Increasing the mud weight to counteract this swelling or sloughing shale, and
to well predict the mud weight before drilling.
Risks / Hazards / Mitigation
Hazard Risk Mitigation
Pack-offs with water
base mud and difficulty
getting casing to bottom
Stuck pipe, potential for
losing well and/or sidetracks
Wiper trips, sufficient MW in
the hole
No cement returns to
mudline on riserless strings
Structural integrity of well
Pump excess cement volumes,
lighten densities with foam
Uncertainty in deep
pore pressure prediction
Well control, kicks
FPWD in drill string, real time
pressure monitoring
High gas, trip gas Well control, kicks Sufficient MW overbalance
Narrow drilling margins Losses, ballooning
Managed pressure drilling,
use contingent casing strings
H2S
Casing/pipe failure, harm to
personnel
Utilize sour service tubularsq,
use special additives in mud to
inhibit sour gas, have H2S
plan on rig
2.10. Determining The Number of Casing Strings and Their Setting
Depths:
a. Determining the hydrostatic pressure:
Ph = .052*γm*h psi
Ph
Hydrostatic pressure (psi)
γm Density of the fluid (ppg)
h True vertical depth (ft)
b. Determine the formation pressure
Pf
= Ph
- 200 psi
c. Determine the hydrostatic gradient (Gh
):
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0.6772 0.7032 0.5373 0.5096 3878.2 3678.2 9.8 7217.8 2200
0.6720 0.6980 0.5211 0.4940 3846.6 3646.6 9.5 7381.8 2250
0.6755 0.7015 0.5309 0.5044 4006.1 3806.1 9.7 7545.8 2300
0.6755 0.7015 0.5308 0.5044 4022.7 3822.7 9.7 7578.6 2310
From the above figure, considering the formation pressure and the fracture pressure
only, we may decide to use one type of mud and only one casing string, but due to other
considerations like formations we use the following strings because of the following
reason:
By looking at the casing setting depths in offset wells we will chose the
following setting depths
Casing
Casing
Size
Bit Size
Setting Depth (feet) Mud Weight
(ppg)from to
Conductor 30" Hole Opener 36" Surface 229.6 9.1 PAD
Surface 20" Bit 26" Surface 1918.8 9.1 PAD
Intermediate 1 13 3/8" Bit 17.5" Surface 3083.2 9.6
Intermediate 2
10 3/4" × 9
5/8"
Bit 12 1/4" Surface 3919.6 10.6
Production
Liner
7" Bit 8.5" 3769.6 4883.6 10.7
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The following Figure indicates type and setting depth of each casing
2.11. Casing Design Using “Analytical Method”:
Design concepts:
• Check for collapse resistance at the lower part
• Check for Tensile Strength at the upper part
• Check for Bursting Pressure at the weakest grade.
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Design collapse resistance at the lower part:
Step 1: Minimum collapse resistance for the bottom section
PC (min)
Minimum collapse pressure
FC
Collapse safety factor
Ph
Hydrostatic pressure at lower part (psi)
γm
density of the fluid (ppg)
h true vertical depth of fluid (ppg)
Step 2: from the drilling handbook select the grade and typical tensile load and
the internal pressure:
Note: if there is more than one casing can be used at different depths, Optimization for
design must be considered for the casing selection.
Step 3: The length of the bottom section is determined as follows:
L1
Length of the first section of casing from the bottom
L2
Length of the second section of casing from the bottom
PCmin2
The collapse resistance of the selected second section
PCmin3
The collapse resistance of the selected third section
H Hole depth (ft)
γm
Mud density (ppg)
FC
Collapse safety factor =1.125
Design tensile strength at the upper part:
Step 1: calculate tensile strength:
WI
Nominal weight of each casing grade
LI
Length of each casing string
Step 2: check if safe or not:
Where, Tensile design factor = 1.8
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Design bursting pressure at the weakest part:
Step 1: The weakest section (lowest grade or min. thickens) is checked of
internal pressure as follows:
Where, Pi bursting pressure resistance of the weakest section equals to internal yield
pressure, psi.
SIMIAN-3
For surface casing 20”
Step 1: for collapse resistance;
Selected grade,
Grade
nominal wt.
(Ibs/ft)
Internal
pressure (psi)
Yield strenght
(psi)
Handbook
collapse(psi)
O.D
(in)
I.D
(in|)
K-55 133 3060 2125000 1500 20 18.73
Calculations;
DEPTH(ft) 1918.8
Collapse factor 1.125
Mud weight(ppg) 9.1
Ph (psi) 907.97616
Pc (psi) 1021.47318
S.F 1.468467337
Safe
N.of joints 48
Step 2: for tensile strength; Step 3: for Bursting;
length (ft) 1920
wt.( Ib) 255360
Cum.wt (Ib) 255360
S.F 8.321585213
Safe
Ph (psi) 908.544
Internal pressure
(psi)
3060
S.F 3.368026205
Safe
For intermediate casing 1:
Step 1: for collapse resistance;
Selected grade,
Grade
nominal wt.
(Ibs/ft)
Internal
pressure (psi)
Yield strenght
(psi)
Handbook
collapse(psi)
O.D
(in)
I.D (in|)
K-55 68 3450 1069000 1950 13.75 12.415
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2.12. Cementing Design
General procedure
1. slurry weight of one sack = weight of dry cement + weight of water +weight of
additives
2. slurry volume of one sack= volume of dry cement + volume of water + volume of
additives
3. slurry volume required = volume of slurry in the shoe track + volume of slurry in
the pocket + volume of slurry to be displaced in annulus
4. No. of sacks =
5. Slurry yield =
6. Total amount of water required = cement mixing water + required water for
additives + spacer volume
7. Displacement volume = volume inside the casing – volume of shoe track
8. Job time = mixing time + surface time + plug release time + displacement time
9. Mixing time =
10. displacement time =
11. plug release time = 15 min
12. thickening time = job time + 30 (min)
SIMIAN-3
For intermediate casing 2
Given Data
shoe track 80 ft
time of release plug 30 min
pocket 20 ft
excess for saftey 35%
mixing rate 25 sack/min
pumping rate 22.46 ft^3/min
safety time 30 min
lead slurry yield 2.4 ft^3/sack
tail slurry yield 1.55 ft^3/sack
lead total mix 14.4 gal/sack
tail total mix 6.52 gal/sack
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casing type grade ID(in) OD (in) Length(ft)
intermediate casing 2
L-80 8.835 9.625 3680
H-80 9.504 10.75 240
Cement program
total cement depth(ft) 3919.6 3919.6
cement type lead tail
cement type depth(ft) 0-3769.6 3769.6 - 3919.6
Density (ppg) 12 15.8
Cement placement
hydrostatic pressure 3948.938 psi
fracture pressure 4113.907 psi
Safe cement placement
Lead and tail design for the section
lead design
volume between 10.75” and 13.375” csgs 50.46205688 ft^3
volume between 9.625” and 13.375” csgs 953.0822218 ft^3
volume between hole 12.125” and 9.625”csg 203.4621875 ft^3
total volume of lead slurry 1629.458729 ft^3
No.of sacks 679 sacks
mixing time 27.15764549 min
volume of mixing water 9777 gal
tail design
volume between hole 12.125”and 9.625”csg 44.46289063 ft^3
vloume of pocket 16.02878689 ft^3
volume of shoe 34.04162313 ft^3
total volume of tail slurry 127.6199559 ft^3
No.of sacks 82 sacks
mixing time 3.293418216 min
volume of mixing water 536.8271692 gal
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Displacement design
displacement volume in 10.75” casing 118.1765376 ft^3
displacement volume in 9.625”casing 1531.873041 ft^3
displacement volume in drill pipe string 507.4460151 ft^3
total displacement volume 2157.495593 ft^3
displacement time 96.05946542 min
thickening time
186.5105291 min
3.108508819 hr
Results
sacks for tail 82 sacks
sacks for lead 679 sacks
total needed water 10314 gal
thickening time
186.5105 min
3.108509 hr
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For liner cementing
Given Data
shoe track 80 ft
time of release plug 30 min
pocket 20 ft
excess for saftey 35%
mixing rate 25 sack/min
pumping rate 22.46 ft^3/min
safety time 30 min
lead slurry yield 2.4 ft^3/sack
tail slurry yield 1.55 ft^3/sack
lead total mix 14.4 gal/sack
tail total mix 6.52 gal/sack
casing type grade ID(in) OD (in) Length(ft) overlap(ft)
production liner L-80 6.366 7 1120 150
Cement program
total cement depth(ft) 4889.6
cement type lead tail
cement type depth(ft) -- 3769.6-4889.6
Density (ppg) 12 15.8
Cement placement
hydrostatic pressure 4541.288 psi
fracture pressure 4719.187 psi
Safe cement placement
Lead and tail design
We will choose only tail for liner for strength
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Tail design
volume between hole 8.5"and 7"csg 122.9424479 ft^3
vloume of pocket 7.877256944 ft^3
volume of overlap 23.76033503 ft^3
volume of shoe 17.6738197 ft^3
total volume 233 ft^3
NO.of sacks 150 sacks
mixing time 6.001102205 min
volume of mixing water 978.1796594 gal
Displacement design
displacement volume in 7" casing 229.7596561 ft^3
displacement volume in 9.625" casing 1604.041282 ft^3
displacement volume in drill pipe string 507.4460151 ft^3
total displacement volume 2341.246953 ft^3
displacement time 104.240737 min
thickening time
155.22 min
2.58 hr
Results
sacks for tail 233 sacks
sacks for lead -- sacks
total needed water 978 gal
thickening time
155.22 min
2.58 hr
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2.13. Drill String Design
Research and field experience proved that buckling will occur if weight on bit is maintained
below the buoyed weight of collars. In practice weight on bit in practice weight on bit
shouldn’t exceed 85% of the buoyed weight of collars
The drill string involves the design of drill collar and drill pipe
Drill collar design procedure
Suitable diameter of drill collar is selected according to the hole to be drilled from table
10-3 H.Rabia Hand book
Hole section Recommended drill collar (OD) in
36 9.5 or 8
26 9.5 or 8
17.5 9.5 or 8
16 9.5 or 8
12 ¼ 8
8 ½ 6 ¼
6 4 ¾
The calculations are as following;
Drill pipe design procedure
1. The diameter of the drill pipe is selected according to the borehole size from hand
book as following
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2. Number of stands
3. From drilling data handbook outside and inside diameter of the drill pipe can be
selected
4. Selection of drill pipe grade
5. From the table of drilling data hand book select the grade
6. Check for collapse
7. From the drilling Hand book select the collapse pressure of the selected grade
8. MOP = Pa
– P
Where;
Pa
( theoretical yield strength ) = Pt *.9
P = (Ldp * Wdp + Ldc * Wdc ) * BF
9. Then repeat the previous procedure for every bit size run in the hole
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SIMIAN-3
Calculations and Design
For 36” hole section; depth (2890 ft)
Design of drill collar
WOB 8000 lb
B.F = 1- (mud weight/steel weight) 0.861068702
OD 8 inch
ID 3.75 inch
WC 133 lb/ft
Lc 82.18292916 ft
Nc number of joint 1.956736409 2 joint
act Lc 84 ft
Design of drill pipe
OD 6.625 inch
ID 5.965 inch
Wp 25.2 lb/ft
Lp 2806 ft
Np number of stand 30.17204301 31 stand
act Lp 2883 ft
W 72177.87847 lb
Y min 16598.01105 psi
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Selected grade for drill pipe;
E-75; Y selected = 75000 psi
The grade is safe for minimum yield strength
Check of collapse
Ph 1367.548 psi
P collapse 2930 psi
Fc = 2.14
The grade is safe for collapse
Pa 67500 psi
MOP 368116.454 Ib
For 20” hole section; depth (4612 ft)
Design of drill collar
WOB 15000 lb
B.F = 1- (mud weight/steel weight) 0.861069
OD 8 inch
ID 3.75 inch
WC 133 lb/ft
Lc 154.093 ft
Nc number of joint 3.668881 4 joint
act Lc 168 ft
Design of drill pipe
OD 6.625 inch
ID 5.965 inch
Wp 25.2 lb/ft
Lp 4444 ft
Np number of stand 47.78495 48 stand
act Lp 4464 ft
W 116103.7 lb
Y min 26699.2 psi
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Selected grade for drill pipe;
G-105; Y selected = 105000 psi
The grade is safe for minimum yield strength
Check of collapse
Ph 2182.398 psi
P collapse 3350 psi
Fc = 1.535
The grade is safe for collapse
Pa 94500 psi
MOP 500308.3 Ib
For 17.5” hole section; depth (5776.4 ft)
Design of drill collar
WOB 16000 lb
B.F = 1- (mud weight/steel weight) 0.853435115
OD 8 inch
ID 3.75 inch
WC 133 lb/ft
Lc 165.8360359 ft
Nc number of joint 3.948477046 4 joint
act Lc 168 ft
Design of drill pipe
OD 5.5 inch
ID 4.778 inch
Wp 21.9 lb/ft
Lp 5608.4 ft
Np number of stand 60.30537634 48 stand
act Lp 5673 ft
W 125098.8234 lb
Y min 32212.84006 psi
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Selected grade for drill pipe;
G-105; Y selected = 105000 psi
The grade is safe for minimum yield strength
Check of collapse
Ph 2883.57888 psi
P collapse 6890 psi
Fc = 2.389
The grade is safe for collapse
Pa 94500 psi
MOP 425388.4413 Ib
For 12 ¼” hole section; depth (6612.8 ft)
Design of drill collar
WOB 20000 lb
B.F = 1- (mud weight/steel weight) 0.838168
OD 8 inch
ID 3.5 inch
WC 138 lb/ft
Lc 203.4234 ft
Nc number of joint 4.843415 4 joint
act Lc 210 ft
Design of drill pipe
OD 5.5 inch
ID 4.778 inch
Wp 21.9 lb/ft
Lp 6402.8 ft
Np number of stand 68.84731 48 stand
act Lp 6417 ft
W 142079.8 lb
Y min 36585.42 psi
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Selected grade for drill pipe;
G-105; Y selected = 105000 psi
The grade is safe for minimum yield strength
Check of collapse
Ph 3644.975 psi
P collapse 6890 psi
Fc = 1.890
The grade is safe for collapse
Pa 94500 psi
MOP 408407.5 Ib
For 8.5” hole section; depth (7569.8 ft)
Design of drill collar
WOB 25000 lb
B.F = 1- (mud weight/steel weight) 0.836641
OD 6.125 inch
ID 2.5 inch
WC 88 lb/ft
Lc 399.4838 ft
Nc number of joint 9.511519 4 joint
act Lc 420 ft
Design of drill pipe
OD 5 inch
ID 4.276 inch
Wp 19.5 lb/ft
Lp 7176.8 ft
Np number of stand 77.16989 48 stand
act Lp 7254 ft
W 149267.7 lb
Y min 42470.57 psi
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Selected grade for drill pipe;
G-135; Y selected = 135000 psi
The grade is safe for minimum yield strength
Check of collapse
Ph 4226.86 psi
P collapse 8760 psi
Fc = 2.07
The grade is safe for collapse
Pa 94500 psi
MOP 348928.9 Ib
2.14. Directional Drilling Trajectory
General procedure
The Given data is:
1. Kick of point (KOP)
2. Build up rate (B.U.R)
3. Total vertical depth (D3)
4. Displacement @ T.D ( X3)
5. L1; length of A.R.C (ft)
6. MD1: measured depth to the end of
buildup (ft)
7. MD2: Total measured depth (ft)
8. X2 : The horizontal departure to the
end of buildup (ft)
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SIMIAN-3
Calculations;
Calculations SIMIAN-3
Radius Of Curvature (R1) 1910
Ω 38.2°
τ 27.2°
θ 11°
Length of Arc 367 ft
The Measured depth to the
end of build section (MD2)
4367 ft
The Horizontal Departure to
the End Of build section (X2)
35.1 ft
T.V.D at end of build(D2) 4364.4 ft
Total measured depth 8083.45 ft
Data for the well SIMIAN-3
Kick Of Point(K.O.P)(D1) 4000 ft
Build Up Rate(B.U.R) 3°/100 ft
Total vertical Depth (D3) 6745 ft
Displacement @ T.D(X3) 500 ft
2.15. Rig selection
1) Pipe Set Back Capacity
36” Hole 26” Hole 17 1/2” Hole 12 1/4” Hole 8 1/2” Hole
N.Weight of
Collars (lb/ft)
133 133 133 138 88
N.Weight of Drill
Pipes (lb/ft)
25.2 25.2 21.9 21.9 19.5
Wsb (lb) = W D.C + W D.P(WB ‘in air’)
in (lb) 83823.6 134836.8 146582.7 169512.3 178413
in (ton) 38.021 61.16 66.488 76.889 80.926
2) Weight Supported by Crown Block
Kelly wt 1815.6 lb
Swivel wt 152443 lb
TB wt 16105 lb
36” Hole 26” Hole 17 1/2” Hole 12 1/4” Hole 8 1/2” Hole
Wmax= Drill string wt + Kelly wt + swivel wt + TB wt
Wm (lb) 254190.2 305200.4 316946.3 339875.9 348776.6
Wm (ton) 115.29 138.44 143.76 154.17 158.2
35% safety factor
Wm (lb) 343156.5 412020.5 427877.5 458832.5 470848.4
Wm (ton) 155.64 186.89 194.07 208.13 213.57
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3) The Maximum Casing Capacity
COND 30” CSG 20” CSG 13 3/8”
CSG 10 3/4”
× 9 5/8”
LINER 7”
+ Landing String
B.F 0.844 0.845 0.85 0.86 0.875
weight in air (lb) 36207.92 255200.4 209657.6 155044 111991.2
effective weight
(lb)
30559.48 215644.3 178208.96 133337.8 97992.3
35% Safety factor
41255.3 291119.4 240582 180006 132289.6
in (ton) 18.7 132 109.13 81.65 60
*Design for Maximum derrick load = 213.57 ton
4) Swivel Selection
*Determination of Maximum Swivel Load Capacity
Maximum Swivel Load = D/Smax
+ Kelly Weight
= 178413 + 1815.6
= 180228.6 lb = 81.75 ton
From Drilling Hand Book, we select the proper swivel:
Depth Capacity 8000 ft
Main bearing dia. 12 1/2 in
Rated dead load capacity 150 ton
Fluid passage dia. 2.25 in
Bail pin dia. 3.5 in
Bail diameter at bend 4 in
Net approximate weight 1480 lb
5) Hook selection:
• Hook is selected according to the maximum weight that will be supported either
during drilling or lowering the casing
• For total hook load during drilling:
Max. Weight = Drill String wt. + Kelly+ Swivel wt = 178413 + 1815.6 + 1480 =
181708.6 lb = 82.421 ton (the maximum)
• For total hook load during casing:
H. L = wt. of heaviest casing in mud + swivel wt =215644.3+ 1480
= 217124.3 lb = 98.485 ton
We will select our hook depending upon the highest load. From Sovonex Tech (A supplier
provides Hooks and Blocks) we will choose HK90.
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Max hook load KN 900
Opening size of main hook mm (in) 12 1/2 in
Rated dead load capacity 155 (6 1/6)
Spring trip mm (in) 180 (7)
Dimensions (LxWxH) 2000*680*600
Weight 1800 kg
6) Hoisting System Selection:
1- For maximum traveling block load:
Maximum traveling block load = Hook load + Hook wt
= 217124.3+1800 = 218924.3 lb = 99.302 ton
From Rotary Drilling Handbook:
API working load strength 100 ton
No. of sheaves 6
Sheave diameter 36 inch
Line size 1 1/8 inch
Overall length 69.5 inch
Weight with no hook 5470 lb
Thickness 20.75 inch
Clevis width 8 1/2 inch
Length with hook 204 3/4 inch
Hook length 19 1/2 inch
Hook width 30 1/2 inch
2- For hoisting cable design:
*From Drilling equipment and machinery (Dr. M. S. Farahat):
Total load supported by hoisting cable = T.B. load + T.B. weight itself
= 218924.3 + 5470 = 224394.3 lb = 101.78 ton
- Consider the maximum tension in the line in pounds, which expected for the drilling
operation:-
Where;
N the number of lines strung, assuming 8 lines
E system efficiency 0.842
TF.L the fast line tension lb
TF.L= 224394.3 / (8*0.842) = 33312.69 Ib
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- Multiply this tension by (3) as safety factor to obtain the safe ultimate strength of the
required cable = 99938.07 lb
- From Drilling Data Handbook, select the cable which has the closest ultimate strength
and has the suitable diameter for hoisting sheaves.
Select 6 * 19 classification wire rope, bright (UN coated)
or Drawn-Galvanized wire independent wire rope core
Nominal
diameter, in
Approximate
mass
Nominal strength ,Ib
Improved plow steel Extra improved plow steel
1.25 2.89 138800 lb 159880 lb
Deadline-load is given by:
TDL= (224394.3*0.9615^8) / (8*0.842) = 24333.47 Ib
7) Crown Block Design:
E.F = 0.842
F.L= 32233.42 lb
D.L= 23545.1 lb
Total crown block load T.C.L = T.B. load + T.B. weight + TFL + TDL
= 218924.3 + 5470 + 32233.42 + 23545.1
= 280172.82 lb = 127.28 ton
*Note: Sheaves of C/B = Sheaves of T/B + 1
- From Drilling Data Handbook, Brantly … We will select the following crown block
depending upon economics and safety considerations:
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API Working Load Strength 325 tons
No. of sheaves 7
Sheave diameter 54 in
Approximate weight 13995 lb
Length “I” beam 108 inch
Diameter of sand line sheaves 24 inch
Drilling line 1 1/2 inch
Length shaft, width block 49 1/2 inch
Cat line 1 1/2 inch
Diameter of cat line sheaves 15 inch
8) Draw-Works Design:
Power = 969 hp
(We will select a motor with 1000 hp rating)
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11) Pressure Losses
12) Mud Pump Horse Power Calculations
13) BOP EQUIPMENT
• Diverter System
Regan KFDS-CSO with 14” diverter lines, 16” flowline and 10 degree flex
• Flex Joint
18¾” with 21” Vetco HMF connection and 10 degree flex
• Riser Connector
Vetco H-4, 18¾” 10,000 PSI WP
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• Annular BOP’s
Two (2) Shaffer 18¾” 5,000 PSI WP
• Ram Preventers
Two (2) Cameron double type “U” 18¾” 10,000 PSI WP
• Wellhead Connector
Vetco H-4, 18¾” 10,000 PSI WP
• BOP Accumulator Unit
NL Shaffer air-electric, 3,000 PSI
• Hydraulic Control Pods
Two (2) NL Shaffer fully redundant with pressure bias system
The selected rig is (ATWOOD EAGLE)
THE EAGLE CAN OPERATE AT WATER DEPTHS OF UP TO 5,000 FEET AND CAN
DRILL DOWN APPROXIMATELY 25,000 FEET.
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Drilling Instrumentation
Petron driller cabin containing Petron Networked Distributed Drilling Data (3D)
Instrumentation System consisting of:
1. Integrated drilling recorder function
2. Dual rig floor touch screen display with dual master panel capability
3. Drilling data hub monitoring:
a) Top drive torque f) Mud pump pressure (2) each
b) Top Drive RPM g) Cement pump pressure
c) Hydraulic hook load h) Casing/annular pressure
d) Hydraulic tong torque i) Flow sensor
e) Crown sensor depth and ROP
4. Mud pit data hub monitoring:
a) Riser boost pressure
b) Mud pump strokes (3 each)
c) Mud pit volume – thirteen (13) sensors in main mud pit system (three [3] pits
have dual sensors) and two (2) sensors in trip tank
5. Drilling data hub and Mud pit data hub are networked to workstation in Toolpusher’s
office and Company Rep’s office (optional)
6. Drillers console consisting of controls, gauges, and lights for the control and
monitoring of approximately 90 items
2.16. Graphically Plots
1) ROP
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2.17. Well Cost
Drilling costs will depend on the depth of the well and the daily rig rate. The rig daily rate
will vary according to the rig type, water depth, distance from shore and drilling depth.
For onshore, it will be <100,000 $/day, and for deepwater offshore, it can be very high
from 150,000 up to 800,000 $/day. The number of days will be a function of depth. For
usual depth up to 20,000 ft, we can assume 70 to 80 days and for deeper depths up to
32,000 ft, a maximum of 150 days.
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Cf Drilling Cost, $/ft
Cb Bit Cost, $
Tc Connection Time, hrs
Tr Bit Rotating Time, hrs
Tt Trip Time, hrs
D Footage, ft
Cr Rig Rent
Tn Non-Rotating Time, hrs
Drilling Cost
Section
36”
Hole
26” Hole
17.5”
Hole
12 ¼”
Hole
8.5” × 10 ¾
“ Hole
Rig Rent 150000 ($/day)=6250 ($/hr)
Bit Cost 3000 $ 4000 $ 5000 $ 7000 $ 9000 $
Drilling Time (hrs) 1.5 11.4 12 49.5 8
Wash & Ream Time (hrs) .4 1.1 2 3 3
Tripping Time (hrs) 8.4 13.2 16.6 21 17
P/U, L/D BHA &DP Time (hrs) .15 .3 .45 .5 2.5
Drill to Enlarge Hole Time (hrs) --- --- --- --- 6
N/U- Testing BOP- Riser Time (hrs) --- --- 3 3.5 2
Drill CEMT & DV & Shoe Time (hrs) 1.5 2 2.8 3.1 5.2
E.LOGS &LWD Time (hrs) --- ---- --- 3 7.5
RAN HSSt,BOP & Riser Time (hrs) ---- ----- ----- --- 112
Survey & Slip &Cut Time (hrs) ----- ---- ---- 5 ---
Back Ream Time (hrs) ----- ------ ---- 3 ---
CIRC & COND Time (hrs) 4.5 5.6 6.5 7.5 7.5
Total Drilling Time (hrs) 14.95 33.6 43.35 99.1 163.2
Total Cost of Section ($) 96437.5 214000 275937.5 626375 1029000
Cost Per Feet for section $/ft 420 126.7 237 749 1060.8
Total Drilling cost of Well ($)
CT = 96437.5+214000+275937.5+626375+1029000
= 2241750
Cost Per Feet ($/ft) 2241750 / 48890 = 45.85
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Cost Table
Phase 36” H 30” C 26” H 20” C
17.5”
H
13 “ C 12”H 9 ” C
8.5” x
10” H
7” liner Completion
Depth( ft) 229.6 229.6 1919 1919 3083 3083 3920 3920 4890 4890 4890
Time (days) .7 .3 1.4 .5 2 .5 4 .6 6.8 .8 3
Material
Tangible ($)
0 15600 0 15000 0 64200 0 54540 0 185749 63000
Material
Intangible ($)
10000 13500 60000 58800 65000 51900 70000 67000 80000 21600 29100
Drilling Rig ($) 105000 45000 210000 75000 300000 75000 600000 90000 1020000 120000 450000
Axillary
Services ($)
15000 19630 23000 138320 35000 10200 56000 69300 89000 9930 317080
Logistics
Services ($)
1500 1400 1650 1800 900 900 850 1000 400 300 1350
Well Cost ($) 131500 95130 294650 288920 400900 202200 726850 281840 1189400 337579 860530
Total Cost ($) 4809499 $
So SIMIAN-3 Will Cost
7051249 $
2.18. Intelligent Well Completion:
The generic term “intelligent well” is used to signify that some degree of direct
monitoring and/or remote control equipment is installed within the well completion.
An intelligent well has the following characteristics:
• It is capable of collecting, transmitting, and analyzing wellbore production and
reservoir and completion integrity data
• It allows remote action to control reservoir, well, and production processes
Intelligent well systems
The objective of the intelligent-well system is to maximize value, which could include:
increased production, improved reserves recovery, minimized capital and operating
expenditures. Systems are monitored and operated to optimize a given parameter by
varying, for example, the inflow profile from various zones or perhaps the gas lift rate.
Remote monitoring and control capabilities include: pressure and temperature sensors;
multiphase flow meters; flow-control devices.
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These points articulate key objectives of the intelligent well system.
• Improved recovery (optimize for zonal/manifold pressures, water cuts, and sweep).
• Improved zonal/areal recovery monitoring and allocation (locate remaining oil and
define infill development targets).
• Optimized production (improved lift, acceleration, and reduced project life).
• Minimized capital investment to exploit an asset.
• Reduced intervention and operating costs.
• Optimized water handling.
Intelligent-well technology can deliver improved hydrocarbon production and reserves
recovery with fewer wells. Intelligent-well technology can improve the efficiency of
water floods and gas floods in heterogeneous or multilayered reservoirs when applied
to injection wells, production wells, or both. The production and reservoir data acquired
with down hole sensors can improve the understanding of reservoir behavior and assist
in the appropriate selection of infill drilling locations and well designs. Intelligent-well
technology can enable a single well to do the job of several wells, whether through
controlled commingling of zones, monitoring and control of multiple laterals, or even
allowing the well to take on multiple simultaneous functions - injection well, observation
well, and production well. Finally, intelligent-well technology allows the operator to
monitor environmental conditions and manage well integrity.
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2.19. Risk Assessment
The oil and gas industry is notoriously dangerous and presents a host of safety
challenges. Of course, this industry can also be incredibly lucrative and firms within
this particular sector can do very well. The key for many companies is to ensure that
all possible risks are considered and planned for, as the financial consequences of
any mistake or disaster can push even the well-funded firm to the brink of or even
into bankruptcy. Here are some of the important things to consider when performing a
quantitative risk assessment:
Potential Situations
Different companies in the oil and gas sector obviously engage in different facets of
the process from drilling to distribution. Of course, the more dangerous aspects take
place when establishing oil sites and beginning the drilling and extraction process. The
scope of the project, the equipment utilized, and the topographical nature of the locale
will all influence the types of problematic situations that may arise during the course of
operations. Thus, one of the initial steps to take to quantify the potential risks involved
with a project is to formulate the various scenarios the company may encounter.
Granted, there is always the possibility that something unexpected will happen and
there is no guarantee that the matter will take a specific direction. Nonetheless, it would
be foolish not to come up with the problems that are most likely to occur so that some
proactive problem solving and mitigation tactics can be set into motion. In addition to
thinking about how much these issues could cost and what it would require to rectify
them, the steps that follow will likely be an offshoot of the different types of situations
anticipated or they may actually be problems on their own.
Hazards to Humans
Oil spills, explosions, and toxic fumes are valid concerns when it comes to working in
anything that is oil and gas related. As a result, one of the more important components
of the risk assessment is an analysis of the potential hazards that the project will have
on the workers directly working at the site, as well as the residents in any surrounding
areas. Unfortunately, these hazards may occur irrespective of a disaster or accident,
and weighing the cost and benefit must occur to ensure that it will not result in
unnecessary human exposure to dangerous chemicals. In addition to ensuring there is
a proactive view as to the potential hazard, it is certainly within the realm of possibility
that injuries or medical conditions that arise could lead to some kind of litigation.
Therefore, it is important to consider the many costs that may be associated with those
sorts of lawsuits.
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Environmental Impact
Even if the risk to humans is relatively low, there is always the possibility of harming
the environment, which can end up having long term deleterious effects on local
residents. Plus, if the environment becomes polluted, whether by massive spill or
unknown leakage, this can disrupt the local food supply, as recently happened in the
Gulf. The environmental impact can end up costing significant sums of money, as the
price of cleanup and restitution to those affected can be an ongoing issue for years
and years into the future. Of course, it is also unwise to be the company that destroys
precious land, and the damaged reputation will result in a whole bunch of other financial
ramifications that are difficult to quantify.
Economic Implications
It is highly unlikely that the oil and gas industry will disappear any time soon, as there
is continued global dependence on fuel and a fair amount of resistance to or simple
disinterest in seeking viable alternatives. And, as mentioned and widely known, there is
no denying the fact that this is a highly lucrative business, even though it is also a highly
risky one. The reality is that all businesses must engage in risk assessments and take
steps to mitigate risks as much as feasible. In this sector, it is obviously vital to perform
these assessments on a regular basis and to ensure that they are accounted for in the
annual budget. This requires sophisticated modeling and financial projections, so it is
best to seek the advice and counsel of a seasoned professional.
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2.20. References
1. Farahat, M.S. Drilling Engineering 1. 2nd. Suez: Suez University, Faculty of
Petroleum and Mining Engineering.
2. Brantley, J. E., Rotary Drilling Handbook. s.l.: Pulmer Publishing, 1961.
3. Adams, N. J. A Complete Well Planning Approach. 2nd. Tulsa: PennWell Books, 1985.
4. Rabia, H. Oil well Drilling Engineering Principles and Practice. U. K.: Graham and
Trotaman, 1985.
5. Bourgoyne, A. T. Applied Drilling Engineering. s.l.: SPE Text Book Series, 1991.
6. Gabolde, Gilles and Nguyen, Jean –Paul. Drilling Data Handbook. s.l.: Editions
Technip, 2006.
7. Nelson, E. B. Well Cementing. s.l.: Schlumberger Educational Services, 1990.
8. C., Gatlin. Drilling Engineeing. Texas: Petroleum engineering, Department of
Petroleum engineering, University of Texas, 1960.
9. Droppert, V.5. Application of Smart Well Technology. s.l.: Delft University of
Technology, December 2000.
10. Al-Mejed, M. E. Hossain & A. A. Fundamentals of Sustainable Drilling Engineering. 2015.
101.
102.
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3.1 Terminology
Symbol Definition Unit
Φd Density porosity log Fraction
Φn Neutron porosity log Fraction
(Φd)sh Density porosity log for shale Fraction
(Φn)sh Neutron porosity log for shale Fraction
Φd corrected Corrected density porosity log Fraction
Φn corrected Corrected neutron porosity log Fraction
Φavg Average porosity Fraction
F Formation factor Dimensionless
Rw Water resistivity Ohm .m
Rwa Apparent water resistivity Ohm .m
Sw Sw Water saturation Fraction
A Lithology factor / archie’s constant -
M Cementation factor -
Φls Apparent porosity of lime stone %
Φss Apparent porosity of sandstone %
Φs Porosity from sonic log %
Φnc1 Corrected porosity from neutron log for shale %
Φnc2 Corrected porosity from neutron log for hydrocarbon %
3.2. Introduction
Formation evaluation is the process of using borehole measurements to evaluate the
characteristics of subsurface formation.
These measurements may be grouped into four categories:
Drilling Operation Logs. Core Analysis.
Productivity Tests. Wireline Well Logs.
Formation evaluation methods
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Well logging is a formation evaluation technique that is used to extract information
necessary for exploration, drilling, production and reservoir management activities.
Log is a graphic representation of the variations of depth versus other parameters.
Wireline log are measurements of physical parameter in the formations penetrated by
borehole, they are run while drilling has been stopped i.e. after the drill string has been
pulled out from the borehole.
It is called also wireline logging due to the wireline cable which carries at its end the
instruments & lower it into the well.
Wireline logging
3.3. History of well logging
1912
Conrad Schlumberger gave the idea of using electrical measurements to map
subsurface rock bodies
1919 Conrad Schlumberger and his brother marcel begin work on well logs.
1927
The first electrical log was introduced in 1927 in France using stationed resistivity
method.
1929
The first commercial electrical resistivity tool in 1929 was used in Venezuela, USA
and Indonesia
1931
SP was run along with resistivity first time, Schlumberger developed the first
continuous recording.
1941 Υ-ray and neutron logs was started
1950 Micro-resistivity array dipmeter and lateralog were first time introduced
1956-60
The first induction tool was used in 1956 followed by formation tester in 1957,
formation density in 1960's
1978-80 electromagnetic tool in 1978 and most of imaging logs were developed in 1980
1990 Advanced formation tester was commercialized
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3.4. Logging tools
3.4.1. GAMMA RAY LOG
The gamma ray log measures the total natural gamma
radiation emanating from a formation. This gamma radiation
originates from potassium-40 and the isotopes of the
Uranium-Radium and Thorium series. The gamma ray log
is commonly given the symbol GR.
3.4.2. Caliper logging
It is used to:
• Evaluate the borehole environment for logging
measurements.
• Identification of mudcake deposition, evidence of
formation permeability.
Caliper Tool:
The Caliper Tool is a 3 armed device that measures the internal
diameter (I.D.) of casing or open borehole completions. This
information is crucial to all types of production logging. The
caliper probe provides a “first look” at borehole conditions in
preparation for additional logging. It uses a tool which has 2,
4, or more extendable arms. The caliper is a useful first log to
determine the borehole conditions before running more costly
probes or those containing radioactive sources.
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The log is used to: “Interpretation Goals”
• measure borehole diameter,
• Location of cracks, fissures, caving, faulting, casing breaks.
• assess borehole quality and stability
• For calculation of pore volume for pile construction.
• Input for environmental corrections for other measurements.
• Qualitative indication of permeability.
• Correlation.
• Correction of other logs affected by borehole diameter
• Provide information on build-up of mudcake adjacent to permeable zones.
• Locate packer seats in open hole.
Notes
• Increasing in diameter of borehole indicates about Wash out Process (ex: Shale).
• Decreasing in diameter of borehole indicates about Invasion process (ex: Porous
Sand).
3.4.3 Porosity Logs
3.4.3.1 Neutron logs
Various concepts of bombarding the formation with energetic neutrons, thermal neutrons,
gamma rays, fast neutrons can be received depending on the log concept. It responds to the
hydrogen index in the different fluids, it is therefore a valuable tool to distinguish oil, water
and gas.
Neutron ToolNeutron mechanism
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3.4.3.2. Sonic log
The sonic log measures the speed of sound in the formation. The log presents slowness,
Δt, which is converted to sonic porosity, assuming lithology, fluid slowness, and the proper
sonic porosity transform. The most common, but not necessarily the most accurate, is
the WYLIE time average (WTA)
3.4.3.3. Density log
The density log measures ρe
,the electron density. This is
converted to bulk density using the following relationship
3.4.3.4. Resistivity log
Used to determine true formation resistivity (Rt), There many types of resistivity logs,
they are listed below:
A. Long normal resistivity log for determining Rt.
B. Short normal resistivity log for determining Rxo.
C. Lateral log for determining Rt.
D. Micro latero log for determining Rmc and Rxo.
E. Induction log for determining Rt in resistive drilling fluid.
Figure 7 sonic tool Figure 8 sonic tool mechanism
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3.4.4.1. Latero Logs
A new electrical logging method called
Laterolog is described which providesfor
better recording of formation resistivity. In
this method a current preferably of constant
intensity, is forced into the formation
perpendicular to the wall of the hole as a
sheet of predetermined thickness by means
of aspecial electrode arrangement and of an
automatic control system.
3.5 Selection of the Tools to run
It depends on what type of information you are about to get and the cost you are willing
to spend.
• Ability to Define Your Need:
• Geological
• Geophysical
• Reservoir
• Petrophysical
• Mechanical
• Type of Information to Acquire
3.6 Quantitative Interpretation
3.6.1 Procedure
Step 1
• Ensure that the logs are “on depth” relative to each other by taking a “marker”
which is an anomaly or a distinctive response that appear on the log
Step 2
• Take the readings from the attached logs (if there are any corrections,
make them carefully).
Step 3
• Calculate shale volume from gamma ray, neutron density and resistivity.
and minimum shale volume depending on theses logs.
Step 4
• Calculate the effective porosity from neuCalculate the effective porosity from
neutron and density log. tron and density log.
Step 5
• Apply correction on effective porosity at zones with washouts
(high sloughing shale).
Step 6
• Calculate water saturation depending on effective porosity and shale
content.
Step 7
• calculate net pay thickness and reservoir thickness depending on cutoffs
• Shale volume less than 35 %
• Effective porosity higher than 12 %
• Water saturation less than 50 %
Figure 10 LWD tool
109. 105 Graduation Project 2020
Well Logging
3.6.2. Correlations
3.6.2.1 Calculation of shale index (Ish):
From gamma ray log:
Where
Υ gamma ray response in the zone of interest.
γ min the average gamma ray response in the clean sand formation.
γ max the average gamma ray response in the cleanest shale formation
3.6.2.2 Calculation of Vshale (Vsh)
From gamma ray log:
- For linear relationship:
Vsh
= Ish
- For larionov equation for tertiary rocks
V = 0.083 × (23.7×Ish
− 1) sh
- For stieper equation
V =Ish
/(3−2Ish
)
- For older rocks, larionov equation
V = 0.33(22 Ish
− 1) sh
- For clavier et. Al equation
V = 1.7−[3.38−(I +0.7)2
]1/2
- From neutron porosity log
Where
Vsh
= (ØN
/ ØNsh
)
3.6.2.2.1 Density correction Neutron correction
ØN
Neutron porosity log reading at zone of interest.
ØNsh
Neutron porosity log reading opposite to the cleanest shale zone.
Porosities corrections
ØDC
= ØDC
− ØDSH
VSH
ØNC
= ØDC
− ØNSH
VSH
3.6.2.2.2 Correction for hydrocarbon effect
Light oil or gas will cause the formation density (ρb) to decrease by an amount of ∆ ρb &
apparent porosity (ØD & ØN) to increase by an amount of ( ∆ØD & ∆ØN ) respectively.
110. Graduation Project 2020
Section 03
106
3.6.2.3 Calculation of effective porosity
3.6.2.4 Determination of Saturation
Depending on INDONESIA equation
Sw Water saturation
Vsh Volume fraction of shale
Rsh Resistivity of shale
Rw Formation water resistivity
Øe Effective porosity
a For clean formation usually equals 1 in sand
3.6.3. Basic Data for Calculation from Logs
Parameter Value Unit
Matrix Density 2.65 g/cc
Hydrocarbon Density 0.168 g/cc
Fluid Density 1 g/cc
Salinity 44560 ppm
Sgr 0.38
a 1
m 1.622
n 1.785
111. 107 Graduation Project 2020
Well Logging
3.6.4. Determination of Shale Parameters
Parameter Value Unit
(GR)max 72.72 API unit
Shale Bulk Density 2.34 gm/cc
Density Porosity of Shale 30 %
Neutron Porosity of Shale 55 %
3.6.5. Determination of Cleanest Formation Parameters:
(GR) min 31.3 API unit
3.6.6. Determination of Water Resistivity:
Rw 0.1214 Ohm.meter
Note: For Well Simian 1
Top 2085 meter
Base 2163 meter
Average Porosity 23 %
Average Saturation 34 %
Average Shale Volume 11 %
Net Pay thickness 21 meter
Hydrocarbon Volume Estimation 3.4 TSCF
