Executive the three development plans is constructed and

Executive Summary

   This report aims at examining the
economics of three depletion drive mechanisms for the development of an
oilfield: natural gas-gap depletion, natural water drive and water injection.

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Excel spread-sheets that integrate production controlling parameters, ex.

STOIIP, are used to obtain production data including first oil production, flow
rates, and point of termination of production. This data is then utilized to
perform the economic analysis and establish costs and barrel ownership. The
economic analysis entails CAPEX, OPEX, annual cash flow, cumulative cash flow,
and revenue distribution calculations. Thus, a comparison between the three
development plans is constructed and a proposition as to which is the most
economically viable is made.  

 

     Using the  ‘Technical Input” table of the excel sheet a
development plan was made by choosing a set number of wells in specific years
with regards to the determined production well potential of 10 mbopd.  Based on the generated production data,
facility capacities’ sizes were adjusted and the well and facilities costs were
estimated. Using the cumulative cash flow, the Net Present Value versus the
discount rates were plotted to obtain the Internal Rates of Return.

 

    The three depletion
strategies yield 10%, 20%, and 40% recovery factors for the gas-cap depletion,
natural water drive, and water injection respectively. The gas-cap depletion
mechanism has the lowest cumulative CAPEX, cumulative cash flow rate at 10% discount
rate, and IRR of 18.46% with 119.9mmstb recoverable oil. At 10% discount rate,
abandonment is initiated in year 16, after only 13 years of production. Natural
water drive has an IRR of 33.71% with a recovery of 240mmstb. At 10% discount
rate, the field produces for 19 years before abandonment with a cumulative cash
flow rate of $1108.5million. The cumulative CAPEX of $1725million is an order
of magnitude higher than the gas-cap depletion, but remains significantly lower
than the $3300million capex of the water injection. However, water injection
has a cumulative oil production of 480mmstb. At 10% discount rate the IRR is
19.045% and the field can produce for 21 years with a cumulative cash flow rate
of $1311.9million, almost just 16% higher than the natural water drive at
almost double the expenditures making the natural water drive a better
recommendation for the core development plan.

 

 

 

 

 

Field Plan, Production Profile, and Reservoir Delivery

   The main prospect for every production plan
is maximizing revenue at the lowest cost. The three plans are considered for
the IRR and NPV at 10% discount rate. The optimum value of NPV and IRR is
achieved by minimizing the costs of wells and facilities while maintaining
maximum recovery.

 

Natural Gas-Cap
Depletion

   This mechanism is
driven by the expansion of and frontal displacement of the pre-existing gas cap
and/or the upward migration of gas from unsaturated oil via counterflow1
to mitigate the pressure decline during production. Consequently, the high gas
production of 147mmscfd in comparison to the other two mechanisms had to be
accounted for by increasing the gas facilities and thus the capex. Figure 3
illustrates the drilling plan over 13 years designed to minimize gas production
rate and facilities capex while considering well recovery potential. Initially
4 wells were drilled in the second year, then 2 in the fourth, and one in years
6,10,11,12, and 13. Between years 5 and 13, drilling was kept minimal in an
attempt to control the gas production rate, the rate exceeded the oil
production rate in year 5. The oil, gas, liquid, water injection and power
capacities chosen were 50mbopd, 150mmscfd, 75mbopd, 0mbwipd, and 225 mblpd/mmscf
including 60mbopd pipeline totaling at $1070million for capital expenditures. The
field achieved the recovery factor of 10%, i.e. 120mmstb. Production peaked in
year 4 at 50 mstb/d (figure 4), one year after first oil production, and
decreased from 50 mstb/d to 0.1 mstb/d in years 24 to 25.

 

Natural Water Drive

   The main controller
in this mechanism is the aquifer. Similarly to the gas-cap depletion, water
influx acts to mitigate the pressure decline driving the oil to the producing
wells. The degree to which water influx affects recovery depends on the degree
of communication between the aquifer and reservoir and the amount of water that
encroaches into the reservoir. For NWD, the drilling plan was covered in the
first 10 years (figure 7). The production profile (figure 8) indicated peak
production of 75 mstb/d in year 4, one year after initiation of production. A
gradual decrease was observed until a rate of 11.5  mstb/d in year 22 followed by termination of
production in year 23. Maximum gas rate production was kept at 58mmscfd. Water
cut occurs in the second year of production, and increases to 47.5% in year 22.

Consequently, oil and liquid facilities’ capacities are increased. The oil,
gas, liquid, water injection and power capacities chosen were 75mbopd, 60mmscfd,
100mbopd, 0mbwipd, and 160 mblpd/mmscf including 80mbopd pipeline totaling at
$875million for capex.

Water Injection

   Water injection is
the use of waterflooding2
to generate and/or increase production from oil reservoirs. The restriction of the
drilling performance to 4 wells per year caused drilling to commence as soon as
possible with 4 wells consistently drilled for the entire 11 years of drilling summing
to 46 wells yielding a 40% recovery factor (figure 11). The production forecast
(figure 12) conveyed a low oil production rate in comparison to that of water
and gas, consequently leading to an enormous increase in facilities capacities
in addition to water injection facilities (figure 9) totaling at $2630million
for capex, inclusive of 46 wells. The oil, gas, liquid, water injection and power
capacities chosen were 125mbopd, 45mmscfd, 450mbopd, 460mbwipd, and 955
mblpd/mmscf including 130mbopd pipeline. Production peaked in year 4 at 121.7
mmstb/d and decreased at a relatively slower rate than the other two plans reaching
22.1 mmstb/d in year 24 at which production terminated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Economic Analysis of the Three Development Scenarios

Natural Gas-Cap
Depletion

   Figure 13 displays
the value of the company across different discount rates. The NPV(10) (figure 14)
is $357.7million, while the ultimate cash surplus NPV(0) is $1117million. Figure
13 shows that the maximum exposure for the project is $1380million without a
discount factor and $1186million at 10% discount rate at which the depletion
plan can deliver $390million if abandoned in year 16. Additionally, the
internal rate of return (figure 15) is 18.5%. Its annual cash flow profile at
10% discount rate (figure 16) indicates that production revenue initiates in
year 2, the pay-as-you-go point occurs between years 2 and 3, and the pay-out
occurs between years 6 and 7. At no discount factor the pay-out occurs almost a
year earlier. As for the profit, the company makes a total of $3929.7million of
in-taxable income which 18% is profit (figure 17-18).

 

Natural Water Drive

    For NWD, the
discounted cumulative cash flow profile (figure 19) indicates the NPV(10) is
$1108.5million, with an ultimate cash surplus, NPV(0), of $2788million and an
IRR of 33.7% (figure 20) making this the most robust depletion plan out of the
three. The maximum exposure for the project is $893million at 10% discount rate
and $1035million without a discount factor. 
The annual cash flow profile (figure 21) at 10% discount rate indicates
that production revenue starts in year 2, the pay-as-you-go point occurs
between years 2 and 3, and the pay-out occurs between years 4 and 5. At no
discount factor the pay-out occurs in the same year.  The plan can deliver about $1137.8million at
10% discount rate if abandoned in 22. As for the profit generated with NWD, the
company makes $8789.7million in-taxable income of which 21% is profit (figure 22-23).

 

Water Injection

    For WI, figure 24 shows an NPV(10) of $1131.8million
with an ultimate cash surplus, NPV(0), of $5249 million. The field can deliver
$1333million if abandoned in year 24. This plan generates $15,657.8million
in-taxable income of which 19% is profit (figure 25-26).  However, the plan has an IRR of only 19%
(figure 27). The annual cash flow profile (figure 28) shows that production
revenue starts in year 2, the pay-as-you-go point occurs between years 2 and 3,
and the pay-out point is between years 7 and 8. At no discount factor the
pay-out occurs almost 2 years earlier. The maximum exposure for the project
occurs in year 2.

 

 

Reservoir
and Development Sensitivities

   It is important to
consider economic sensitivities, both those relating to the reservoir’s
technical properties such as STOIIP and those related to development and
external factors for example oil price. To demonstrate sensitivities, the NWD
scenario is taken as a case study.

 

Sensitivity
to STOIIP and RF

   Figure 29 shows the
effect of having a variance in the expected STOIIP by 10% higher and lower on
the discounted cumulative cash flow with respect to the discount rates. While figure
30 displays fluctuations in the recovery factor by 5% higher and lower. There
is a direct relation between both sensitivity variables and the NPV(10) and the
IRR. As the STOIIP increases, the NPV(10) increases, however the IRR only
increases by about 1%. On the other hand, as the RF increases, the NPV(10) and
IRR both slightly increase. A decrease in the RF has a bigger impact, as the
IRR decreases from 33.7% to 27.5%. Additionally, an increase in both factors,
can cause an increase in the facilities capacities.

 

Sensitivity to Oil Price

  
Figure 31
shows fluctuations in the oil price by $5 more and less. Similar to the RF, a
slight increase in the price causes the NPV(10) to increase and the IRR to
increase from 33.7% to 38%. However, when the price decreases by the same
amount, the impact is higher, reducing the IRR from 33.7% to 24.5%. 

 

Sensitivity to Construction Time

   
Figure 32
shows the impact of having delays in the construction period by 1 and 2 years.

At no discount rate, a 2 year delay to the initial 36 months construction
period has a higher net present value. This is due to the deducted operational
costs. However, at higher discount values (10%), a two year delay decreases the
NPV(10) and causes a 17% decrease in the IRR.

 

Sensitivity to Drilling Costs

   
Figure 33
displays the impact of increasing and decreasing the drilling costs slightly by
$2million. This change can be due to changeable prices of drilling muds,
casings, and cements. As the well capex increases, the NPV(10) and IRR both
decrease.

 

 

The extent of changes to the NPV(10)
and IRR, are visually summarized in figures 34 and 35 respectively.

 

 

Development
Risks, Mitigations, and Contingency

   Risks in development
plans can be due to reservoir and non-reservoir factors. These can cause high
economical loss and decrease in value.

 

Exploration
Risks

   For this field no
appraisal well was drilled. Data acquired are from a short duration PVT test.

Consequently, uncertainties in pertrophysical and geological data can yield
inaccurate production forecasts. Estimations of STOIIP, contact points (gas-oil
and oil-water contacts), and sizes, locations, and conditions of faults (open
and close) will either be unknown or have lower accuracies.

 

   The strength of the
underlying aquifer, which is a controlling variable for the NWD plan is
unknown. The aquifer is thought to be large in size with a small overlying
gas-cap.  The most accurate method to
acquire accurate date is to commence production and obtain production data while
choosing the safest depletion plan. In this study, that is recommended to be
the NWD. If the aquifer proves to be insufficient in size or strength,
introducing some injectors as a secondary plan is a helpful option. Furthermore,
there is no archive for drilling data in the country this being a first-oil
discovery. Higher safety margins should be introduced in drilling planning and
pressure gradients calculations, as risks are higher.

 

Political
Risks

   This being the
first-oil in this country, there is unfamiliarity between the oil industry and
the government. Though, hopeful for revenue, the fiscal terms seem to be
improved.  If a relation of mutual gain
between both the company and the government is established through a detailed
inclusive contract this can prevent any futuristic conflicts from occurring.

Additionally, awareness amongst locals, including advertisement and local talk
summits for instance, can contribute to creating a positive outlook on the
development plan to avoid political backlash. Finally, the political stability
of the country must be assessed and considered as in a case of a civil war, the
company loses money and will be inable to recover any capital or operational
expenditures.

 

Operational
Contingencies

  Operational
contingencies are critical to consider and have systems of prevention installed
for them. These include blowouts during drilling and/or facilities damage
throughout production.

 

Recommended
Development

    With regards to
previous sections, the recommended development plan is the NWD. It has the
highest rate of return 33.7% (figure 36). It has a significantly higher NPV(10)
than the ND and is only 16% lower than the WI, with almost half of the
development expenditures. The most critical risk for this development however
is the strength of the aquifer.

1 “The simultaneous downward movement of
oil to balance the upward flow of gas. This diametric flow pattern is referred
to as counterflow.” (PetroWiki, 2014)

2 The use of water injection; it is “accomplished by “voidage
replacement”—injection of water displaces oil from the pore spaces, but
the efficiency of such displacement depends on many factors (e.g., oil
viscosity and rock characteristics).” (PetroWiki, 2014)