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Abstract

Steam assisted gravity drainage,
which is a form of steam flooding that involves continuous injection of surface
generated steam into a horizontal injection well to reduce heavy oil viscosity
cause the oil to flow more easily towards a parallel drilled horizontal producer
well, is one of the most commonly used thermal stimulation technique for
extracting heavy crude oil. It is preferred because of its cost-effectiveness, the
availability of water and its relatively higher recovery factor.

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This technique can, however, be
improved by generating steam downhole rather than injecting surface generated
steam. An in-situ steam generator will reduce heat loss and ensure the high
quality of the steam being injected into the reservoir which makes for an
improved oil recovery. Such a steam generator has been developed and a field
study to evaluate the performance of the in-situ steam generator in improving
oil recovery over conventional SAGD has been carried out on an abandoned heavy shale
oil field that is being rejuvenated.

The results from this field
study were used in a reservoir simulation model generated using Schlumberger’s
Eclipse Compositional Simulator for steam stimulation. The model was history
matched to reflect the heavy shale oil field production under natural depletion
drive and steam stimulation. Several simulation runs were made to evaluate the
performance of the in-situ generator in a vertical well and for three steam-assisted
gravity drainage (SAGD) well arrangements scenarios. An analysis was also
carried out to compare the economic impact of the different simulation
scenarios.

The different sensitivity runs
gave outcomes that indicated that the use of the patented in-situ steam generator
in SAGD led to 360 barrels of incremental
production of oil per year over
conventional SAGD. The simulation study show that in-situ steam generation and
injection is an effective and environment-friendly enhanced oil recovery
technique that has the potential to replace conventional steam field
applications as it is a game changer. With the in-situ steam generator,
steam quality can be maintained 100% of the time throughout the life of the
process, which leads to guaranteed faster in-situ oil heating.

 

 

Keywords

Heavy Oil,
Thermal recovery

 

 

1.       Introduction

Low recovery factors
are usually associated with oil production from heavy shale oil reservoirs
under natural depletion drive. This is due to the high viscosity of the heavy oil
and the tightness of the formation. Therefore, there is a need to employ enhanced
oil recovery (EOR) techniques to extract incremental heavy crude oil from such
reservoirs. Heat is introduced into the subsurface accumulation of organic
compounds to reduce the viscosity of such compounds for the singular purpose of
recovering the fuels through associated producer wells. This process, according
to Prats (1982), is called thermal enhanced oil recovery (TEOR).

The
performance of thermal recovery is dependent on the reservoir temperature,
depth of the accumulation, oil saturation and availability of steam or hot
water. Thermal methods are classified based on the heating process employed into
steam-assisted gravity drainage (SAGD), in-situ combustion and hot water
flooding method. Sometimes steam is co-injected with solvents, gases and air into
the reservoir to enhance recovery. However 98.1% of all thermal EOR production
is yielded through steam, whereas 1.7% is produced thanks to in-situ
combustion. Hot water flooding generates an incremental oil recovery of only
0.2%.

A general term for injection processes that introduce heat
into a reservoir. Thermal recovery is used to produce viscous, thick oils with
API gravities less than 20. These oils cannot flow unless they are heated and
their viscosity is reduced enough to allow flow toward producing wells. During
thermal recovery, crude oil undergoes physical and chemical changes because of the
effects of the heat supplied. Physical properties such as viscosity, specific
gravity and interfacial tension are altered. The chemical changes involve
different reactions such as cracking, which is the destruction of carbon-carbon
bonds to generate lower molecular weight compounds, and dehydrogenation, which
is the rupture of carbon-hydrogen bonds. Thermal recovery is a major branch of
enhanced oil recovery processes and can be subdivided in two types: hot fluid
injection such as steam injection (steamflood or cyclic steam injection) and
hot waterflooding and in-situ combustion processes.

In the
literature, simulation studies of shale oil thermal recovery are very limited.
In fact, only a few attempts were made in order to model the process using
commercial compositional simulators. These attempts were not successful due to
the complexity of the reservoir and lack of data.

This
research’s objective is to present a numerical simulation study of a shale oil
reservoir, test the capabilities of a patented in-situ steam generator and
compare its optimum SAGD performance to that of conventional SAGD. 

 

2.       Background Theory

When producing
from heavy oil reservoirs, operators tend to produce with primary recovery
methods for as long as possible. Cold production is the most common form of
primary production in heavy oil reservoirs. However, cold production gives a
recovery factor of only 1-10 % in heavy oil reservoirs. Accordingly, there is a
rapid need for secondary recovery methods. Cold production with artificial
lift, including injection of a light oil, or diluent, to decrease the viscosity
might be a valid option. When cold production is no longer economically
feasible, tertiary methods in the form of thermal recovery are usually
implemented (Curtis et al., 2002). According to Gates (2010), cold production
is typically feasible in heavy oil reservoirs with high solution gas and
in-situ viscosities less than 50,000 cp. The viscosity of Slocum field oil
ranges from 1000-3000 cp. Moreover, the accumulation of the oil is anticlinal
bound on north by a fault and elsewhere by oil- water contact and the primary
recovery method led to only marginal recovery of about 1 percent. So, thermal
recovery methods are employed.

Most common
process in thermal recovery is hot water flooding. In this, heated water is
injected into the reservoir in order to displace the in place oil immiscibly
(Farouq, 1974). Hot water flooding is similar to conventional water flooding;
the only difference is the temperature increase with respect to the injected
water and hence hot water flooding is more applicable to heavy oil reservoirs.

However, the
limited success of this method can be attributed to viscous fingering. It
occurs frequently in hot water flooding, because the injected water has higher
mobility compared to that of the oil-initially-in-place, which results in a
poor volumetric sweep efficiency resulting in early breakthrough of water and a
relatively low recovery of oil. Which is the reason Farouq (1974) judged
steam-based flooding a much-preferred method compared to hot water flooding

Steam flooding
is the most successful tertiary recovery technique for heavy oil reservoirs,
which makes it one of the most commonly used EOR technique. Here, steam is
injected into the reservoir in order to displace residual oil.

Figure 4.1: Steam
flooding process diagram
(Farouq, 1974)

 

The injected
steam increases the temperature inside the formation and as a result oil moves
towards the production wells as shown in the Figure 4.1. The
mechanism behind steam flooding is the reduction of oil viscosity by steam
injection. Moreover, the increased reservoir pressure (energy) owing to steam
injection plays an important role in it. (Konopnicki et al., 1979; Volek and Pryor, 1972; Wu, 1977).

Steam-assisted gravity drainage (SAGD) is a steam flooding technique
that was developed in Canada. SAGD method was initially developed to recover
bitumen from the Canadian oil sands. In Athabasca bitumen reservoirs, SAGD is
the most used commercial steam based process (Gates, 2010). The basic concept
of SAGD is two parallel horizontal wells (see Figure 4.2 below) which have a
large contact area with the formation. Prior to the steam injection, a
preheating period takes place. Heating is conducted in the injection well and
production well to obtain communication between the wells. After the preheating
period, hot steam is injected in the top horizontal well and introduced to the
reservoir. The heat causes the oil viscosity to decrease and thereby increases
its mobility (Curtis et al., 2002). As the

Figure 4.2: SAGD two-well disposition
(Curtis et al., 2002)

viscosity is
reduced, the heavy oil thins from the oil sands and separates. A steam chamber
develops and the density difference causes the steam chamber (the steam
saturated zone) to rise to the top of the reservoir and to expand gradually
sideways. After some time it will allow drainage from a very large area. The
mobilized oil then drains to the production well situated at the bottom of the
reservoir due to gravity. The oil and condensed water are thereafter produced
at the production well. The reason why this method relatively new is due to
directional drilling as it has only been possible to drill horizontal wells the
last 10-15 years.

The injected
steam reduces the oil viscosity down to 1-10 cp, depending on the reservoir
conditions such as temperature and fluid properties of the oil. (Speight,
2009).

The vertical
distance between the injector and the producer is normally 5-7 meters (Speight,
2009). This method is very efficient and it is claimed that it will increase
the recovery by 60-70 % of the oil-initially-in-place and is therefore the most
efficient thermal recovery method (Speight, 2009). In addition to high ultimate
recovery the SAGD method improves steam-oil ratio compared to other steam-based
methods (Speight, 2009).

The SAGD
process is very stable compared to other methods due to no pressure-driven
instabilities such as coning, channeling or fracturing. It is merely a gravity
driven process and is therefore extremely stable as the process zone grows only
by gravity segregation (see Figure 4.3 below).

Figure
4.3: Active gravity segregation in SAGD process (Curtis et al., 2002)

Despite all
these advantages of SAGD, there are some technical issues related to the SAGD
methods. These are related to low initial oil rate, artificial lifting of
bitumen to the surface, horizontal drilling and operation, and the implementation
of SAGD where there are very low reservoir permeability, low pressure or bottom
water (Speight, 2009).  

One of the identified
drawbacks of SAGD is the cost of steam injection as it is important to keep the
steam-oil ratio as low as possible to maximize the economical outcome. Steam
generated in-situ with the patented in-situ steam generator is shown in this
simulation study to be more efficient and cost effective than conventional
steam generation.

 

3.       Reservoir Simulation Model

 The oil and
gas reservoir simulator, ECLIPSE 300,
managed by Schlumberger Information Solutions (SIS) was used to construct the
reservoir model

Well tops and location
(coordinates) were used to generate a TOPS map. The constructed static model is
a 3-dimensional 33x52x11 Cartesian gridblock system (see Figure 6.1 below).
Grid blocks lengths and widths came out to be 129.13 and 203.48 ft,
respectively. It was decided to discretize the Carrizo formation in 11
different layers. Such characterization was made based on lithological makeup
of each layer.

Resistivity logs were utilized
to determine average water saturation in each layer for 4 vertical wells (Well
#11, Well #12, Well #15 and Well #16). Neutron logs were used to determine
porosity. Porosity ranged from 30 to 33%. Petrel was utilized to generate water
saturation as well as porosity maps.

Figure 0.1: The
heavy oil field areal view with Grid layout (BLACKBIRD ENERGY)

 

The current water saturation is
about 55%. It was revealed that most of the oil is locked in the bottom layers
of the reservoir (see Figure 6.2 below). The shallow oil has already been swept
by a waterflood done on a nearby field. Permeability values were also used
taken into account well testing information. According to the operator,
BLACKBIRD ENERGY, LLC, permeability had an average of 3000 md.

Rock-fluid properties data were
lacking. PVT properties based on the API gravity of 19o (see Figure
6.3 showing a wellhead sample) were used in the conceptual model.

Figure
6.2: The heavy oil field wellhead oil snapshot (BLACKBIRD ENERGY)

Compositional fluid data were
generated using a PVT flash calculation experiment taking into account an
average reservoir pressure and temperature as well as the oil API gravity (19o).
In heavy oil simulation practices, heavy oil is characterized as
one-component system. Only oil gravity is discretized, brine and gas specific
gravities are defaulted. Oil viscosity, a major parameter that has direct
implications on outcome of thermal recovery performance, has been plotted as a
function of reservoir temperature (see Figure 6.4 below). Laboratory
measurements indicated that viscosity dropped from 710 cp at a temperature of
100 oF to 4.5 cp at 350 oF. The thermal conductivity of
rock and fluid rock and the rock volumetric heat capacity were estimated to be
at 26.259 BTU/ft3/oF and 10.351 BTU/ft/day/oF,
respectively.

 The following data (Table 6.1) was used in the
estimation of both quantities taken into account that the heavy oil field
hydrocarbon-bearing formation, Carrizo sandstone, is made of 10% sandstone, 35%
siltstone and 55% shale:

 

Figure 6.3: Oil viscosity variation with
temperature

Table 0.1: Data used in the evaluation of specific heat and thermal
conductivity

Rock type

Composition, %

Density, lb/ft3

Specific  heat (BTU/lb*oF)

Thermal conductivity
(BTU/hr*ft*oF)

Sandstone

10

130

0.183

0.507

Siltstone

35

120

0.204

0.396

Shale

55

145

0.192

0.603

 

Initial
reservoir temperature was originally set at 75o. Cap and base rock
connections are also established by assuming that all grid blocks in top of
layer 1 (33×52) and bottom of the layer 11 (33×52) are all active.

In addition, well gridblock
locations were determined using a Petrel areal map. The oil-water contact was
set at 547 ft. Pressure at that datum was calculated to be 264 psia. Production
wells (Well #11, Well #15, Well #16) were completed from top of layer 9 to
bottom of layer 11. The in-situ steam generator was set in Well #12, across
from layer 9 (bird nose at 350 ft). Production well bottom hole flowing
pressures were initially set at 100 psi, based on well testing information. Temperatures
in producers were initially set at 75 oF based on temperature logs.
Production rates were defaulted. Injection temperature and injection water flow
rate were also set at averages of 350 oF and 33 bbl/day,
respectively. Injection well initial pressure at bird nose depth of 350 oF
was calculated to be 183 psia.

The generated data file
(Appendix A) was input in Eclipse 300 compositional simulator to mimic steam
injection.

 

4.       Results and Discussion

Heavy Oil
Compositional Simulation

7.1        Heavy Oil
Compositional Simulation

7.1.1      Pure depletion

Table 7.1 below depicts 2012
average monthly production from vertical wells (Well #11, Well #14 and Well
#16). Total cold production was at 1483 barrels.

Table 0.1: Observed production data (No firing)

Date

Average Monthly Oil
Production, stb

March
2012

175

April
2102

101

May
2012

121

June
2012

94

July
2012

163

August
2012

124

September
2012

109

October
2012

125

November
2012

165

December
2012

73

January
2012

125

February
2012

108

Total 2012 Production

1483

 

The daily average came to be at
4 bbl/d. Observed water cuts were at around 1:2. Despite high permeabilities of
3000 md, oil production was hampered mainly because of a high viscosity, 710 cp
at a reservoir temperature of 100 oF. 

A conceptual reservoir simulator
was developed to mimic cold production. Relative permeability tables were
created using the Stone 2-phase oil-water model. Connate water saturations were
taken at 0.5 to better characterize present-state water saturations as depicted
from logs. Initial simulations yielded higher oil flow rates. kro and krw end
points were altered to match reported monthly oil production (see Figure 7.1
below). 

Figure
7.1: Sensitivities to match cold monthly oil production

Match relative permeability
profiles are shown in Figure 7.2. Curves indicate a preference to water flow
and that Carrizo oil-bearing formation is oil-wet.

Figure
7.2: Cold production match oil-water relative permeability profiles

The match is acceptable (see
Figure 7.3 below). The simulated 2012 cumulative cold oil production of 1482
bbls is as good as the reported 1483 bbls. Further fine tuning was not
conceivable due to the fact that monthly production from each active well was
not accessible, hence the disparity in both profiles. 

Figure
7.3: Best cold production match

7.1.2      Vertical well steam stimulation

3-month steam simulation was
performed to match August through October 2013 hot production data. The in-situ
steam generator, hot bird, was set at 350 ft as highlighted by the operator.
The injector Well #12 with wellhead located in block (23,35) was completed in
layers 9 through 11. The hotbird nose pressures (Figure 7.4 below)
varied from a peak of 220 psi corresponding to the firing of 1 MMBTU/day down
to an average of 140 then to 110 when 200 to 300 MBTU/day were fired.

Figure
7.4: Steam generator nose pressures (BLACKBIRD ENERGY)

Sensitivities on kro and krw end
points (see Figure 7.5 below) were executed to better match the field
production profile. kros were reduced from 0.4 to as low as 0.0293. Water
relative permeability end points were also adjusted to match water production.
krws were fine-tuned from 0.7 to 0.35.

Figure
7.5: Hot production vertical well sensitivities

Match relative permeability
profiles are shown in Figure 7.6. Hot oil production relative permeability
endpoints were amplified from 0233 (cold) to 0.0293 (hot) to replicate better
oil transmissibility. Hot water relative permeability endpoints were increased
from 0.132 (cold) to 0.35 (hot) to imitate increased level of water due to
steam injection. 

Figure
7.6: Hot production match oil-water relative permeability profiles

The
operator reported a 3-month hot production of 600 bbl. Simulation runs
predicted 624 bbls worth of steam-assisted production. The match obtained (see
Figure 7.7 below) is acceptable. 

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