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PNG 492 Final Report
Spring 2014
Group 14
Texas Tea
1st May 2015
Quanhui Zheng
Xi Yang
Logan Harper
Daneul O’Neil
Chad DiStanislao
Chandler Kisow
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Table of Contents
Introduction and Gantt Chart ............................................................................................................ 3
Phase 1 – Reservoir Modeling Overview ........................................................................................... 4 - 6
Phase 2 – Drilling Engineering Overview ........................................................................................... 7
Phase 3 – History Matching ............................................................................................................... 8 - 14
Phase 4 – Sweet Spot Model Simulation ........................................................................................... 15 - 23
Economic Analysis .............................................................................................................................. 24
Safety and Environmental Concerns .................................................................................................. 24 - 26
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Introduction
We are currently in the third phase, third semester, of a capstone project in the Petroleum and
Natural Gas Engineering program at The Pennsylvania State University. Throughout this project we are
supplied with real life data from an oilfield that is currently active. The first phase of the project is about
reservoir modeling and sweet spot determination. The second phase is about designing a drilling
program. Finally the third phase is about history match, cyclic steam injection, and production. Enclosed
in this report is a brief overview of phase one and two and a discussion on phase three. Below is a Gantt
chart depicting our work throughout phase 3 and 4.
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Phase 1 – Reservoir Modeling Overview
The first phase of our project consisted of a reservoir modeling theme. We were given a
structure map of a specific field that showed the depths to the top of the formation of interest. We
were also supplied with data from a number of wells that were drilled within this formation and the
locations of them within the reservoir. After splitting our structure map up into grid blocks (fig. 1), we
used a computer programing software along with the reservoir property data (porosity, net pay
thickness, and water saturation) from the given wells to create structure maps of the reservoir
properties (fig. 2 an 3).
Figure 1 - Reservoir Area Showing Gridlines.
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Figure 2 - Thickness in Pay Zone
Figure 3 - P50 Unit Recoverable Oil
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Once we generated the contour maps of reservoir properties we were able to determine a
sweet spot in the reservoir. Figure 4 below shows our structure contour map with our chosen area of
sweet spot. The sweet spot was based off of our P50 Recoverable Oil and Net Pay thickness.
Figure 4 - Initial Selection of Sweet Spot Area
The P50 approach to calculating OOIP in phase 1 of our engineering design capstone gave us a
value of P50OOIP = 1.0726e+09 STB.
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Phase 2 – Drilling Engineering Overview
The second phase of our project we were given drilling data from a couple of the wells located
across our reservoir. We used this data along with data from phase 1 of our capstone to determine a
drilling program for a well within our chosen sweet spot that we will plan to drill. We began by
determining what type of reservoir we were dealing with by looking at log data from wild cat wells. We
concluded that the type of reservoir is from the Cretaceous period and is a limestone containing a heavy
oil. This type of reservoir will need to be cyclically steam injected to successfully produce from. Since
we are cyclically steam injecting we choose to drill a horizontal well. There are many benefits to drilling
horizontal wells including, reduction of footprint, greater penetration area within pay zone, and easier
capability of cyclic steam injection. An example of a typical horizontal well profile is shown below in
figure 5.
Figure 5 - Horizontal Well Profile
Along with choosing which production technique to use and what type of well to drill, we chose
all other aspects of the drilling process as well. These aspects included, horizontal well deliverability,
pore and fracture pressure gradient, casing design, mud design, cement design, bit program and an AFE.
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Phase 3 – History Match
In this phase of the project we were give production data from some wells in the reservoir. We
used this data along with our production results to perform history matching. We used history matching
to make the data of our sweet spot in the reservoir and our well more accurate. We used production
data from a well that is located close to our designated sweet spot to get our base data. Once we got a
good set of base data we were able to get more in depth with our history matching. We used the
history matching to get a more accurate value for matrix permeability, fracture spacing, permeability
and porosity. Once we got the values for these properties we input the values into our computer model
to get production data.
We decided to choose a well located at (x=443512.94m, y=2146575.57m) in the reservoir to
perform the history matching plan. The end point of this well is at (x=443027.06m, y=2145226.99m).
The location of this well is right at the sweet spot we chose and can show the correct properties for the
formation in our sweet spot area. The horizontal length of this horizontal well is 1434.38m, which is
calculated by the two coordinates shown above.
Figure 6 - Reservoir Map Showing Horizontal Wells
By using the well log for this well, we find the pay zone of this well is between 3262ft (MD) to
6346ft (MD). By matching the deviation log of this well, we found the pay zone thickness is about 60ft.
Thus, for the model we constructed in the computer program, the block size will be 20m (65.62ft) in the
x direction, 20m (65.62ft) in the y direction and 60ft in the z direction. Figure 7 below shows the top
view of the model we constructed. The size of the reservoir is 41 blocks (x-direction) * 60 blocks (ydirection) * 1 block (z-direction). The well is located NE-SW direction. However, considering the
convenience to locate the well in our history matching reservoir model, we placed it right in the middle
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of the model and the North direction is twisted about 19.81 degrees counterclockwise. Also, we
calculate the average water saturation and average porosity by using the well log. The result is
Sw=0.229806 and Φ=0.217631. Then we put these two parameters into the model we constructed. We
need to use another program to generate random numbers for matrix permeability, fracture
permeability, and fracture spacing. The x and y direction matrix permeability is randomly drawn
between 10-500md, and vertical matrix permeability is chosen between 10-50md. X, Y, and Z direction
fracture permeability is randomly drawing from 500-1321md, 500-3211md, and 500-7500md. The
upper limit is decided from the reservoir data provided and the lower limit is decided by max possible
permeability. Also, the fracture spacing is chosen in the range of 15-30ft randomly and the range is
decided by reservoir data.
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Figure 7 - Top View of Model
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For this well, we find that the best period for history matching is from 10-Dec-14 to 25-Dec-14.
The reason for choosing this time period for history matching is that in this period, the area remains
undisturbed and the closest parallel horizontal well did not produce or inject. At the time, only another
parallel horizontal well (500m/1640ft away) is in production and the effect of this well is limited on the
well we used for history matching.
Between the several runs we used, we chose the best two that match our data to show in the
report. Figure 8 shows the oil production rate versus time. The blue line is the field data that was given
to us. The orange and grey lines are the production results that we were able to get after history
matching in the sweet spot that we chose. We ran many test runs but chose to show only the best two
test results that we got from our work. Our test 1 production starts off slightly higher than the actual
field data but levels out and ends at just about the same. Our test 2 productions starts off slightly lower
than the actual field data but, like test 1, ends at just about the same. The starting production data
could be different for us because of the assumptions that were made or the fact that the other wells
around, which we don’t have enough injection or production data in this time period, do have some
effects on the oil production data on our test well used for history matching.
Oil production Rate (bbl/D)
10-Dec14
11-Dec14
12-Dec14
13-Dec14
14-Dec14
15-Dec14
16-Dec14
Cumulative Oil Production (bbl)
Field data
Test 1
Test 2
Field data
Test 1
Test 2
258
265.3
237.6
258
265.3
237.6
255
249.9
230.6
513
515.2
468.2
257
237.1
219.9
770
752.3
688.1
261
226.1
210.75
1031
978.4
898.85
259
216.7
202.9
1290
1195.1
1101.75
141
208.4
196
1431
1403.5
1297.75
138
201.1
189.9
1569
1604.6
1487.65
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17-Dec14
18-Dec14
19-Dec14
20-Dec14
21-Dec14
22-Dec14
23-Dec14
24-Dec14
25-Dec14
26-Dec14
27-Dec14
Table 1 – History matching Data
142
194.5
184.45
1711
1799.1
1672.1
140
188.6
179.55
1851
1987.7
1851.65
139
183.3
175.1
1990
2171
2026.75
145
178.4
171.05
2135
2349.4
2197.8
141
174
167.3
2276
2523.4
2365.1
141
169.9
163.9
2417
2693.3
2529
142
166.1
160.7
2559
2859.4
2689.7
145
162.6
158.9
2704
3022
2848.6
141
159.3
153.8
2845
3181.3
3002.4
144
156.2
152.35
2989
3337.5
3154.75
148
153.3
149.9
3137
3490.8
3304.65
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Oil production Rate (bbl/D)
300
Oil production Rate (bbl/D)
250
200
150
100
50
0
12/9
12/11
12/13
12/15
12/17
Field Data
12/19
12/21
12/23
Test 1
Test 2
12/25
12/27
12/29
Figure 8 - Oil Production Rate (bbl/D) in the month of December 2014
Cumulative Oil Production (bbl)
Cumulative Oil Production (bbl)
4000
3500
3000
2500
2000
1500
1000
500
0
12/9
12/11
12/13
12/15
12/17
Field Data
12/19
Test 1
Figure 9 - Cumulative Oil Production in the month of December 2014
12/21
12/23
Test 2
12/25
12/27
12/29
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Figure 9 show the cumulative oil production through the month of December in 2014. The blue
is the field data that we were provided with. The orange and grey lines are our best comparable
matches to the field data.
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Figure 10 - Pressure Distribution at 12-27-2014
The above graph (fig. 10) is the pressure distribution at 12-27-2014, which is the end point of
our matching period. It shows that the reservoir model constructed is big enough that at the end out
matching period, the production of the well is not affected by the boundary effect of the model we
constructed. Thus, we can generate correct data in our history matching.
By comparing both the graph of oil production rate and cumulative oil production versus time,
we can find that Test 2, shown above, matched the real well production data. Thus, we need to extract
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the permeability and fracture spacing data from the program result. The result is shown in table 2
below.
Matrix Permeability
Fracture Permeability
(md)
(md)
12.271
788.132
12.271
2191.839
17.274
2947.263
Fracture Spacing (ft)
27.318
x direction
(i)
y direction
(j)
z direction
(k)
Table 2 – Matrix and Fracture PErmeability
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Phase 4 – Sweet Spot Model Simulation
In the final phase of our project we used a computer program to test production of our well we
designed in the second phase of the project located in the sweet spot determined from the first phase.
We tried a cyclic steam injection program and traditional five-spot model as means of stimulation for
our well. To begin with, we got production results from our well without running any stimulation to
compare the results after stimulation. We saw a great increase in production by stimulating with steam
injection rather than not. We chose a cyclic steam injection plan of three wells. We thought that this
would give us the best results in the end. The goal of the cyclic steam injection is to increase the
temperature of the reservoir. Once the temperature of the reservoir is increased, the viscosity of the oil
in the reservoir will decrease, increasing production.
Firstly, we need to construct our sweet spot model. From the design we made before, the
sweet spot is located in the north-west part of the whole reservoir. The coordinates is 442300m443600m in x-direction and 213500m-214700m in y-direction. Thus, the size of the model is 1300m
(4265ft) * 1200m (3937f) * 60m (197ft). For each block, the size is 20m (65.62ft) in both x and y
direction and 60m (197ft) in z direction. The next step is to put in the water saturation distribution data,
porosity distribution data, and net pay distribution data. Also, we put in the matrix permeability data (in
three directions), fracture permeability data (in three directions) from the history matching result, and
also the fracture spacing data. After that, we inserted in the rock-fluid parameters, PVT parameters, and
also viscosity information. The graph shown below (fig. 11) is the fluid relative permeability graph we
used in the reservoir model.
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Figure 11 - Fluid Relative Permeability Graph
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The sweet spot reservoir is then constructed and we need to try several different patterns
including three wells with cycling steam injection and traditional five-spot patterns.
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Figure 12 - Net Pay
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Figure 13 - Well Location Plan
The figure 12 above shows the five spot design and figure 13 above shows the well location plan
for cycling injection method. After running the program, we generate the cumulative oil and water
production graph as shown below:
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Figure 14 - Five Spot Design
Figure 15 - Cyclic Injection Design
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It is clear that for the cycling steam injection plan, we produce more oil (908964 STB in this plan)
than the five-spot design (181163 STB) in the five-year producing period (From 03-25-2015 to 3-252020). Also, it produces less water at the same time, so it is more economical. Below (fig. 16) is the oil
production rate (STB/Day) for all the wells:
Figure 16 - Oil Production rate (STB/Day) for all the wells
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For the injector/producer switching well (Well 2), the oil production rate curve and water
injection curve is shown below in figure 17:
Figure 17 - Injector / Producer Switching Well
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Well 2 is the only well that is switching between producer and injector. Well 1 and well 3
remain producer at all time. However, all three wells are in cycling period. Here is the oil production
rate graph for well 1:
Figure 18 - Oil Production Rate for Well 1
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It is worth it to mention that we also performed hydraulic fracturing around the wellbore
because out matrix permeability is relatively lower. So hydraulic fracturing could be used to help
optimizing our recovery of oil and the fracture plan used is shown below:
Figure 19 - Permeability with Fractures
In all, we produced 908964 STB oil, 801886 STB water, and injected 848879 STB water steam by
using this plan.
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Economic Analysis
The net present value (NPV) of the project can be calculated by considering the revenue and
expenses over the period of the project. The revenue will be calculated in terms of NPV by using the
simulated production and the present value of crude oil, $66.18. In phase 2, the cost of implementing a
production well in this field was estimated to be $806,000, while a dry hole cost was estimated to cost
$450,000. The price of an injection well will be estimated as the price of a dry hole well with the cost of
steam injection added. The NPV will be calculated for the five year operation.
Revenue from oil recovery:
908,964 STB * $66.18/STB = $60,155,237.52
Cost of well construction:
2 * $806,000 + 1 * $450,000 = $2,062,000
Operational cost (steam):
848,879 STB * $.05/STB = $42,444
Operational cost (other):
*additional cost (labor, etc)
NPV = $60,155,237.52 - $2,062,000 - $42,444 - (*additional cost (labor, etc)) = final amount
* Additional costs are subject to change due to labor rates and current economics.
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Safety and Environmental Concerns
As far as our group is concerned, no engineering design is complete without taking safety and
potential environmental impact into account. This is especially true when drilling into reservoirs and
handling large amounts of extracted hydrocarbons. Ensuring safety and the integrity of the land is a
crucial part of hydrocarbon extraction design. With our design we plan to meet all of the Occupational
Safety and Health (OSHA) standards and directives. OSHA requires employers to provide workers with a
workplace that does not have any recognized hazards that are likely to cause death or injury. This
requires using the correct equipment for the job including pipes that can withstand required pressures
and properly functioning pressure monitoring devices. Proper safety equipment will be worn by
employees at all times on the well site including: eye and face protection, head protection, occupational
foot protection, and respiratory protection if necessary. Prepared shut in procedures are also put in
place in the event of kick that could become a potential blowout. Practiced and prepared exit routes and
strategies were put into place in case of a serious incident occurring. All required and necessary accident
prevention signs and tags are in place to reduce risk of accidental human error.
When drilling for hydrocarbons there is large amount of hazardous material to consider and deal
with. This mainly includes the hydrocarbons themselves and different chemicals used in the process.
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There can also be dangerous gases encounter when drilling into the ground, such as H2S. Containing
hazardous material is the biggest challenge to minimizing the environmental footprint of a well. Dealing
with flammable and combustible liquids, proper storage and handling of liquefied petroleum gases, and
hazardous waste operations and emergency response are all key factors in responsibly dealing with
hazardous material.
The Bureau of Safety and Environmental Enforcement’s standards must be met as well, to
ensure minimal environmental impact. These include plan for shut in due to potential blowout, plans for
immediate action following a blowout, having well-design, casing, and cementing to be independently
certified by a professional engineer, keeping logs of any mishaps and any leakage of hazardous materials
into the environment, and show evidence of adequate knowledge and understanding of all safety
practices as well as environmental laws.