02/08/2013 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB27 | |
| SB26 | |
| SB27 | |
| Presentation: What It Takes to Keep Our Legacy Fields Alive. | |
| Adjourn |
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
| = | SB 27 | ||
| = | SB 26 | ||
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
February 8, 2013
3:30 p.m.
MEMBERS PRESENT
Senator Cathy Giessel, Chair
Senator Fred Dyson, Vice Chair
Senator Peter Micciche
Senator Click Bishop
Senator Anna Fairclough
MEMBERS ABSENT
Senator Hollis French
Senator Lesil McGuire
COMMITTEE CALENDAR
PRESENTATION: WHAT IT TAKES TO KEEP OUR LEGACY FIELDS ALIVE
- HEARD
SENATE BILL NO. 27
"An Act establishing authority for the state to evaluate and
seek primacy for administering the regulatory program for dredge
and fill activities allowed to individual states under federal
law and relating to the authority; and providing for an
effective date."
- MOVED SB 27 OUT OF COMMITTEE
SENATE BILL NO. 26
"An Act relating to the Alaska Land Act, including certain
authorizations, contracts, leases, permits, or other disposals
of state land, resources, property, or interests; relating to
authorization for the use of state land by general permit;
relating to exchange of state land; relating to procedures for
certain administrative appeals and requests for reconsideration
to the commissioner of natural resources; relating to the Alaska
Water Use Act; and providing for an effective date."
- MOVED SB 26 OUT OF COMMITTEE
PREVIOUS COMMITTEE ACTION
BILL: SB 27
SHORT TITLE: REGULATION OF DREDGE AND FILL ACTIVITIES
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
01/18/13 (S) READ THE FIRST TIME - REFERRALS
01/18/13 (S) RES, FIN
02/02/13 (S) RES AT 10:30 AM BUTROVICH 205
02/02/13 (S) Heard & Held
02/02/13 (S) MINUTE(RES)
02/04/13 (S) RES AT 3:30 PM BUTROVICH 205
02/04/13 (S) Heard & Held
02/04/13 (S) MINUTE(RES)
02/08/13 (S) RES AT 3:30 PM BUTROVICH 205
BILL: SB 26
SHORT TITLE: LAND DISPOSALS/EXCHANGES; WATER RIGHTS
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
01/18/13 (S) READ THE FIRST TIME - REFERRALS
01/18/13 (S) RES, FIN
02/02/13 (S) RES AT 10:30 AM BUTROVICH 205
02/02/13 (S) Heard & Held
02/02/13 (S) MINUTE(RES)
02/04/13 (S) RES AT 3:30 PM BUTROVICH 205
02/04/13 (S) Heard & Held
02/04/13 (S) MINUTE(RES)
02/06/13 (S) RES AT 3:30 PM BUTROVICH 205
02/06/13 (S) Heard & Held
02/06/13 (S) MINUTE(RES)
02/08/13 (S) RES AT 3:30 PM BUTROVICH 205
WITNESS REGISTER
SCOTT JEPSEN, Vice President
External Affairs
ConocoPhillips Alaska
Anchorage, AK
POSITION STATEMENT: Discussed the role that technology has
played in the development and the off take of the rate on the
North Slope.
ALAN CAMPBELL, Supervisor
Greater Kuparuk Area (GKA) Reservoir and Planning
ConocoPhillips Alaska
POSITION STATEMENT: Was not able to testify because of technical
teleconference difficulties.
BOB HEINRICH, Vice President
Finance
ConocoPhillips Alaska
Anchorage, AK
POSITION STATEMENT: Talked about how the state's fiscal policy
drives investment in Alaska's Legacy Fields.
DAMIAN BILBAO, Head of Finance
BP Exploration Alaska
Anchorage, AK
POSITION STATEMENT: Discussed how the state's fiscal policy
drives investment in Alaska's Legacy Fields.
SCOTT DIGERT, Reservoir Management Team Leader
Greater Prudhoe Bay area
BP Exploration Alaska
Anchorage, AK
POSITION STATEMENT: Discussed how the state's fiscal policy
drives investment in Alaska's Legacy Fields.
DAN SECKERS, Tax Counsel
ExxonMobil
Anchorage, AK
POSITION STATEMENT: Discussed how the state's fiscal policy
drives investment in Alaska's Legacy Fields.
ACTION NARRATIVE
3:30:17 PM
CHAIR CATHY GIESSEL called the Senate Resources Standing
Committee meeting to order at 3:30 p.m. Present at the call to
order were Senators Dyson, Micciche, Bishop, Fairclough, and
Chair Giessel.
SB 27-REGULATION OF DREDGE AND FILL ACTIVITIES
3:31:24 PM
CHAIR GIESSEL announced SB 27 to be up for consideration.
SENATOR DYSON moved to report SB 27, version A, from committee
with individual recommendations and attached fiscal note(s).
CHAIR GIESSEL announced that, without objection, SB 27 passes
from the Senate Resources Standing Committee.
3:31:59 PM
At ease from 3:31 to 3:34 p.m.
SB 26-LAND DISPOSALS/EXCHANGES; WATER RIGHTS
3:34:01 PM
CHAIR GIESSEL called the meeting back to order and announced SB
26 to be up for consideration.
SENATOR MICCICHE said some of his constituents had concerns
about their ability to appeal. His response was that they had to
become engaged at some point before the appeal, and the second
concern was water reservations. So, he wanted to respond that a
person or NGO has never been given a water reservation and that
hadn't changed. He also stated that experience has shown that
groups or NGO's with a good case are generally able to convince
a political subdivision to support their water reservation
request.
SENATOR DYSON moved to report SB 26, version A, from committee
to the next committee of referral with individual
recommendations and attached fiscal note(s).
CHAIR GIESSEL announced that, without objection, SB 26 passes
from the Senate Resources Standing Committee.
3:35:48 PM
At ease from 3:35 to 3:37 p.m.
SB 27-REGULATION OF DREDGE AND FILL ACTIVITIES
3:37:31 PM
CHAIR GIESSEL reconvened the meeting and recognized Senator
Fairclough.
3:37:47 PM
SENATOR FAIRCLOUGH said she wanted to comment about a question
that was asked on SB 27. She explained that when the department
was before the committee she asked for a comparison of the 402
process where the state had successfully gotten waste water
primacy, and she hadn't received that yet. She said she put a no
recommendation on the [committee report] because she wanted to
know what it looks like from an operating perspective.
^Presentation: What it takes to keep our legacy fields alive.
Presentation: What it takes to keep our legacy fields alive.
3:38:28 PM
CHAIR GIESSEL announced that today's agenda was a presentation
on what it takes to keep our legacy fields alive and she
welcomed the first presenter, Mr. Jepsen from ConocoPhillips.
3:39:06 PM
SCOTT JEPSEN, Vice President, External Affairs, ConocoPhillips
Alaska, Anchorage, AK, said he would talk a little bit about the
role that technology has played in the development and the off
take of the rate on the North Slope. He would focus on fields
that ConocoPhillips operates; BP would focus on the other fields
on the North Slope and that should cover other fields where
ConocoPhillips has an interest. This topic is broad and deep,
and today he was going to "tiptoe" through it. He hoped to give
them a good idea just how leveraging technology is and how it
will continue to be leverage as the fields continue to mature.
3:40:10 PM
The first slide was a timeline of the fields that ConocoPhillips
has operated on the North Slope. It starts in 1981 with the
Kuparuk Field and goes to their development at the CD5 drill
site at Alpine. In between are major milestones related to
technology (for simplicity the others were left off); he would
give them some idea of how they work and the impact that they
have on production and development. The major milestones related
to technology are EOR (enhanced oil recovery) and seismic
evolution (focusing on coil tubing drilling).
He showed how Alpine had benefited from all the historical
technology that had been developed on the North Slope, first
detailing how EOR works. For example, the original oil in place
in the Kuparuk Field was about 6 billion barrels, gigantic by
any standard. So, you can take the percentages for the various
mechanisms and multiply it times the oil in place and come up
with the theoretical amount of oil that one might get under the
various recovery mechanisms.
He showed pictures of a rock that had undergone some original
completion that had high residual oil in it (no EOR had had been
applied). In a field like Kuparuk you might get in the range of
15 percent recovery without using any EOR, he said. After
applying water flood, the most common type of enhanced recovery
used and that has been around for many decades, the rock looked
white. After applying a miscible injectant (MI) there wasn't a
whole lot of oil left - and that's their goal. They want to make
sure there is no oil left in each reservoir. But Mr. Jepsen
said, the real world is not quite a clean as these pictures.
SENATOR FAIRCLOUGH asked how much recovery happened after water
flood.
MR. JEPSEN replied about 35 percent recovery and injecting
miscible gas results in about 8-10 percent more, but even under
the best of conditions there are billions of barrels left in
these reservoirs.
3:44:50 PM
The way water flood works, you drill a well, inject water into
it and that provides pressure to push oil towards the producing
well; the water itself tends to sweep the oil out of the
reservoir. At Kuparuk they also employed a technology called
immiscible water-alternating gas injection (WAG). He explained
that in the early days Kuparuk produced a lot of gas but didn't
have any place to store it. So, they injected it back into the
reservoir, itself. This started to create a very large gas
bubble, which made production a bit of an issue, because in the
end a lot of gas might be produced and very little oil. So, the
engineers got very creative and suggested injecting a slug of
gas followed by a slug of water followed by a slug of gas and
spreading this process out over the entire field. That allowed
them to lower the gas saturation from what was in the gas
injection area (which also helped push some of the oil out of
the reservoir). After that they followed up with immiscible
alternating gas process which means they took natural gas
liquids NGL, some of which are produced indigenous to the
Kuparuk field and some of which are brought in from Prudhoe Bay,
and mixed it with the lean gas and created the miscible
injectant. "Miscible" means if you could see this process in the
reservoir you would see a really smooth interface between the
two fluids which helps control the flood itself. Then the
miscible injectant actually acts like it's washing the rock as
it moves through the reservoir removing the residual oil that is
left behind when the oil itself moves forward in the reservoir.
This is followed with water and if another slug of miscible
injectant is needed they will do that. About two-thirds of the
Kuparuk field has undergone miscible injectant. The rest depends
on technical analysis of how well it's going to work (a function
of reservoir quality) whether all the facilities are out there
and a number of other factors. It has been one of the key
components to maintaining the recovery rate in the Kuparuk River
field.
3:47:09 PM
MR. JEPSON said seismic is another type of leveraging technology
for recovery. In 1967, 2D seismic gave them a very rough idea of
geology, but no detail; it gave a poor idea of faulting in the
Kuparuk field at first. Back then they would run 2D swat data,
which means they ran a number of lines fairly close together and
then skipped tens of miles and did another set of lines close
together and then ran another set that was at a 90 degree angle
to that and so on. The information from this kind of data gave a
very rough idea of the subsurface; you could see large
geological structures and might be able to pick out some sands,
but no fine detail. They had a very poor idea of how faulted the
Kuparuk field was when they first started developing it, but
after shooting 3D seismic in the mid-1980s they found a lot
more. So that radically changed how they developed the field; it
meant they were going to drill a lot more wells and do a lot
more analysis to make sure they efficiently swept the oil out of
the field.
Fast forwarding to this decade, Mr. Jepsen said 4D seismic is
now being done. This means they shoot a seismic survey and then
come back some time later (one or three years) and shoot another
survey over the same area. They compare those surveys and, based
upon some processing technology, they can see areas where the
character of the acoustic signal has changed. That can mean a
lot of things. So, the engineers go back in and look at
geological and production data from the well pattern and
reservoir models and try to decide if it means they bypassed
some oil or where they need to add injector. The real leverage
is that it highlights the areas where they need to focus because
it shows more potential.
3:49:43 PM
SENATOR FAIRCLOUGH asked if switching technologies is why wells
aren't being drilled on the North Slope now, because people are
trying to determine the best place to pursue a resource.
MR. JEPSEN answered the amount of drilling they are doing now is
a function of the tax system in the state. Between Kuparuk and
Alpine three and half rigs running and the decision to bring
more drilling tools up to the North Slope will be a function of
how the state competes overall with other places where money is
being invested right now.
SENATOR FAIRCLOUGH asked if all things were equal inside of a
taxing environment if they are drilling as many wells with this
new technology as they have in the past.
MR. JEPSEN replied that they didn't have this kind of technology
15 years ago, but they are trying to work through the candidates
they have in a reasonable fashion.
3:52:45 PM
SENATOR MICCICHE asked if they are producing more water because
of the EOR specifically or just because of what is in the
formations as oil becomes scarcer.
MR. JEPSEN replied that the water rate is going up because of
the water injection. The initial drive for the field was
primarily solution drive meaning expansion of the oil through
gas expansion.
SENATOR BISHOP asked if he meant the water adds no value.
MR. JEPSEN said he meant the water adds value through the role
that it plays in producing more oil. He moved on to describe a
breakthrough in coil tubing drilling that is employed primarily
on the North Slope because of its unique circumstances. The
North Slope was developed from an onshore platform on gravel
pads, drilling directionally to access the reservoir. As these
fields matured and other places were identified for drilling, it
became a lot more cost effective to think about using an
existing well bore not only because drilling a new well is more
expensive, but because of the constraints on pad size,
facilities and permitting. This technology was developed
primarily at Prudhoe Bay to go back into Prudhoe Bay well bores
and do "side traps." Coil tubing itself has been around for a
while, but the real breakthrough came from trying to downsize
the drilling tools to put on the end of it. The steel coil is
stored on a reel and is continuous for thousands of feet; it's
highly flexible, so very short radius turns can be made to get
into a reservoir after milling through the well bore. In the
late 90s that technology was pushed further by downsizing the
tools more to get into even smaller 3.5 inch tubing (from 4 inch
tubing) that existed in most of the Kuparuk wells. Today this
technology is being used for some really exotic things.
3:57:00 PM
He showed a graph of Kuparuk field production and noted that
they are getting about 22 percent, 25,000 barrels a day, out of
EOR and 27,000 barrels a day out of what was labeled "Base."
They got other production out of well workovers, stimulations
and "refracs" that are called "well interventions." The top
layer indicated production from the satellites.
MR. JEPSEN said Tarn was brought on in the late 1990s along with
Tabasco, Melt Water and West Sak, which have contributed
substantially to production. If they hadn't done any of that
work and just stayed with the base production, they would be
producing about 27,000 barrels a day rather than 112,000 barrels
a day. Clearly, he said, ConocoPhillips had been investing and
putting a lot of time and effort into maintaining production and
increase recovery.
3:58:33 PM
MR. JEPSEN moved to the "Alpine story". It was discovered in
1994 and came on stream in 2000. It really represented a
breakthrough in terms of field development as he couldn't think
of any other field that was developed from day-one using
horizontal injector producer pairs; it saved on the number of
wells that are needed. It was a tough sell within ARCO at the
time, which is where he was working. But the other thing that
was a little unique about Alpine at the time is that the
Secretary of the Department of Interior didn't want anything
they built in the wetlands of the Coleville River to be
connected with the Kuparuk or the North Slope infrastructure. So
they agreed to do this as a means to get the permit for
development and even now there is no road that permanently
connects Alpine to the rest of the North Slope. That results in
increased costs, particularly during the summer time when they
have to fly or boat everything in. In the winter time they build
an ice road and try to move as much stuff over there as they
can.
3:59:51 PM
Alpine has benefited from all the technology he had described so
far, Mr. Jepsen explained. ConocoPhillips does 4D seismic and
EOR and uses extended reach drilling, and is moving ahead with
its next development out there, the CD5 drill site (NPRA). It
took about five years to get the permit and this will be the
first production out of NPR-A that gets to one of the key issues
that producers face in Alaska, which is cycle time from first
deciding to do something to first production, because it takes
years. In other places in the Lower 48, like Texas, you are
talking months.
SENATOR FAIRCLOUGH asked if that is because land is in private
ownership in other places versus state ownership in Alaska.
MR. JEPSEN answered partly, but it has more to do with the fact
that on North Slope if you're going to put a drill site down,
you can't just put it down and drive on it. If you do, your rigs
will sink up to the tops of their wheels and you won't be able
to get them out; your trucks will sink in, too. You just can't
operate. So, if you are going to operate efficiently on gravel,
you have to mine it, dry it and place it; after it has
"seasoned" then you can move on it. In addition, a lot of the
North Slope is pretty fragile ecosystem and require wet land
permits. "It's just the environment they are in."
MR. JEPSEN said he would let Mr. Campbell talk about future EOR
technology, since he is an expert. He stated that they aren't
done trying to innovate in these fields, but it won't be cheap.
4:02:02 PM
ALAN CAMPBELL, Greater Kuparuk Area (GKA) Reservoir and Planning
Supervisor, ConocoPhillips Alaska, introduced himself.
4:03:34 PM
At ease from 4:03:34 to 4:03:46 p.m.
4:03:46 PM
MR. JEPSEN said he would cover for Mr. Campbell, because of the
teleconferencing difficulties. Some of the problems they deal
with are just making sure they inject things like miscible fluid
or water that moves through the reservoir in a flood-like
fashion, meaning it doesn't move through certain portions faster
than others. So, they look at things like polymers to make sure
of getting a smooth front when using injections. They also look
at chemical EOR where additional chemicals are injected into the
reservoir to further get more oil off of the rock particles
themselves and thermal and non-thermal techniques for heavy oil
recovery (like steam injection and propane). There is no
economically viable process for producing heavy oil on the North
Slope even though it is a very large resource and that is
probably still decades away.
SENATOR DYSON said he had been told that C02 is really helpful
in lifting heavy oil and wanted him to comment on that in
addition to telling him what "Darcy" is.
MR. JEPSEN replied that "Darcy" is a measure of permeability.
The higher the Darcy number the more permeable it is and the
easier fluids flow through it. CO2 can be beneficial in getting
heavy oil, but where ConocoPhillips is working it won't be
miscible like he described earlier. It can do things like swell
the oil or reduce viscosity, but there are lots of issues in
terms of trying to inject CO2 and have it contact very much of
the fluid. Because there is such a vast difference between the
viscosity of the CO2 and the viscosity of the oil that typically
when you inject it, it's just going to the highest permeability
zone like a dart resulting in "conformance issues." They do it
in small areas, but you're just not efficiently or effectively
contacting much of the reservoir. That's not to say it's not one
of the tools that they continue to try to look at.
SENATOR DYSON asked if he thought we ever will be able to get
credit from the feds for injecting carbon.
MR. JEPSEN replied he hoped so, but he also hoped they didn't
have to get into that world either. He wanted to leave them with
the thought that there is a lot of potential still out there and
that they are working on it, but it's going to be expensive. The
Legacy Fields are the big target and that is where they can get
a quick return for their investments, much quicker than in other
places.
4:07:52 PM
SENATOR MICCICHE asked if he was talking about more expensive
octa-lats (octalateral well) and that sort of technology for
infield legacy production.
MR. JEPSEN answered yes, that is what they are doing these days.
As they move toward the flanks of the field, they are now
developing 10 ft. thick sands that weren't economic 30 years ago
The easy oil is gone. Initially, when they drill the wells at
Kuparuk they'd get a 5,000 barrel a day well, no water and a
little bit of associated gas; at Prudhoe Bay you'd get 15,000 to
20,000 barrel a day well. Today they don't get those rates and
often times after they have drilled some pretty complex
sophisticated wells they get some water back with it as well. It
doesn't mean the target isn't there, but that it's more
expensive and more challenged.
4:09:23 PM
SENATOR DYSON said many of the new fields do not produce as much
as one well at Kuparuk.
MR. JEPSEN agreed that these fields are prolific and continue
being so. For an idea of how much costs have gone up, he
compared the initial Alpine development and a picture of what
the CD-5 will probably look like. Alpine had 92 wells and a full
production train, living quarters and an airport, two drill
sites and cost about $1.4 billion. Thirteen years later CD-5 is
16 wells (maybe as much as 21), a small drill site, a short
bridge, a road and a couple of pipelines that connect it back to
Alpine and cost about $1 billion. The price of doing business on
the North Slope has gone up and there is more competition for
the equipment needed up there as well. He could drill way more
than 15 wells for $1 billion anywhere else in the Lower 48 and
not have to wait years to get it on stream.
SENATOR BISHOP asked for examples of cost drivers.
MR. JEPSEN answered steel, labor, day rates on wells, and cost
of fluids; everything up here has just gone up much faster than
the rate of inflation.
4:12:11 PM
BOB HEINRICH, Vice President, Finance, ConocoPhillips Alaska,
Anchorage, AK, said he would set the stage on why ACES inhibits
investment. He showed the PFC analysis of different countries'
fiscal regimes on an average government take calculation using
$100/bbl price of oil. The average government take is the ratio
of the amount of compensation paid to taxing authorities or
third parties for third-party royalties compared to the
available cash.
4:13:13 PM
PFC broke ACES into new developments and existing production
activities. Under both cases ACES shows up at the higher end of
the taxing jurisdictions that average 70-75 percent. This is
typically higher than OECD countries that carry similar
political risk and places where ConocoPhillips spends a big part
of its capital budget each year.
4:13:58 PM
ACES is part of the problem making not only the average tax
rate, but the marginal government share part of the problem,
too. The state's share includes royalties, property tax,
production taxes and state income taxes; then there is the
federal portion. To illustrate the marginal tax concept, Mr.
Heinrich said under ACES when oil prices increased from $100 to
$101 at a marginal state/federal tax rate of 80 percent, the
producer only retains 20 cents of that dollar increase in price.
Due to the fact of progressivity as prices increase, the
producer receives less and less of the incremental dollar. For
every dollar end cost they can reduce at today's prices, only 28
cents of that dollar comes back to their bottom line.
MR. HEINRICH said as they evaluate projects across the range of
prices, the concept of marginal share actually impacts their
analysis of investment decisions.
4:15:55 PM
SENATOR BISHOP asked if he had authorization for expenditures in
Kuparuk that aren't funded at this time.
CHAIR GIESSEL interrupted saying they are talking about the cost
of technology today and would get into the fiscals at another
time.
SENATOR DYSON said even though it costs a lot more to produce
the oil now that he thought the state let them deduct all the
expenses. Was he missing something?
MR. JEPSEN answered yes; they get to deduct Capex when
calculating the production tax value on which ACES is based and
then see what the average tax rate would be. But from his
perspective, that was done because ACES is so egregiously high
that they are still talking average tax rates of 70 with all
those deductions.
SENATOR DYSON asked him to clarify the 20 percent they didn't
get paid back on.
MR. JEPESEN explained that he was describing that ACES is based
on the production tax value of the oil, a net cash type of
system. So, if ConocoPhillips does something to save a dollar in
operating costs they will only see 20 cents of that, because it
increases production tax value, which increases their tax rate.
4:20:06 PM
In summary, he said technology and innovation have been a key
role on the North Slope and will be important in the future. He
encouraged the legislature to consider the fact that they are at
a disadvantage because of Alaska's remoteness, high costs,
transportation costs and putting the framework of the state in a
way that makes other regimes look good. But if you are looking
to level the playing field, given all the other things they have
to contend with, looking at production incentives for Legacy
fields is going to be important.
4:20:16 PM
SENATOR MICCICHE asked looking 30 years out if things are more
economical and ConocoPhillips continues producing, is increased
production on the perimeter of those fields more likely because
the probability of infrastructure being built might make outer
areas more attractive.
MR. JEPSEN answered as they move towards the "feather edge" of
the reservoir, he couldn't speculate on what else might be out
there. But right now, because these are marginal, infrastructure
is being minimized now. The only place ConocoPhillips has
expanded so far is in the southwest portion of Kuparuk the 2S
development.
4:21:48 PM
CHAIR GIESSEL thanked him and said they would hear next from BP
Exploration Alaska, one of the operators in Prudhoe Bay on
technology and efficiencies since 1977 and how it has affected
production.
4:22:25 PM
DAMIAN BILBAO, Head of Finance, BP Exploration Alaska, Anchorage, AK,
introduced himself.
SCOTT DIGERT, Reservoir Management Team Leader in the Greater
Prudhoe Bay area, BP Exploration Alaska, Anchorage, AK,
introduced himself. He had worked in Alaska but was working in
London for ARCO when it merged with BP and "jumped at the
opportunity" to come back here.
MR. BILBAO said that BP had a long track record of employing
technology, which he would go into in depth today. While they
operate other fields on the North Slope, today he would focus on
Prudhoe Bay, North America's largest oil field. He said that BP
operates Prudhoe Bay with a 26 percent working interest on
behalf of co-venturers, ConocoPhillips ExxonMobil and Chevron.
He said that Prudhoe Bay covers over 300 square miles and when
it was originally discovered the oil in place was estimated to
be approximately 23 billion barrels with an additional 40
tcf/gas. With the technology of the time, BP estimated they
would be able to recover approximately 9 billion barrels, but
they have recovered 12 billion barrels so far and see
opportunity to produce up to 14 billion in total using some new
technologies.
4:25:09 PM
They have not only improved the recovery at Prudhoe Bay but have
also been able to share the learning from Prudhoe with other
fields on the North Slope and elsewhere in the world, evidenced
in part by the more than 200 Society of Petroleum Engineers
technical papers that have been written about it. BP's
operations at Prudhoe Bay are a case study in oil field
development where young and up-and-coming technical folks get
trained, many from the University of Alaska system.
4:26:18 PM
MR. BILBAO said BP always starts by looking to their strategy
for guidance; it defines what opportunities they focus on.
Billions of barrels can be recovered and the question is what
order they are recovered in, which ones meet all the multiple
criteria that have to be met in order for them to compete
locally for investment. First they ask themselves what can be
done in the area of efficiency and they have already heard today
about some of the challenges faced in Alaska and growing costs.
They are also very proud of their good safety performance; 2012
was the safest year on record, a 60 percent reduction since
2009. The other areas they look at are technology and fiscal
policy, but today they would focus on technology. He turned the
conversation over to Mr. Digert.
MR. DIGERT took them to a cartoon illustration of how their
Prudhoe Bay reservoir is laid out and what they have done to
develop it on the surface. Underground Prudhoe Bay is a very
large oil reservoir with a very large gas cap overlying it and
water underneath oil. Their wells produce a mixture of oil, gas
and water that comes up through their flow stations and
gathering centers. Those process the oil and prepare it for sale
down the TAPS to Valdez where they export by tanker primarily to
the West Coast for refining and marketing.
The gas produced goes to the central gas facility where it is
chilled and processed to remove the natural gas liquids (NGL)
which gets blended back into the oil pipeline also for transport
through TAPS and sale. A portion of the NGLs is mixed with gas
to make miscible injectant. The rest of the gas is used as fuel
for Slope operations: compression (mostly), power and light. The
majority of the gas, dry residual gas, goes to the central
compressor plant where it's compressed back to 4,500 psi and
injected back into the gas cap where it is used to support the
reservoir pressure that helps produce out the oil.
In addition to re-injecting the gas Mr. Digert said they inject
water, initially, sea water that pushes the oil sideways to the
producing wells. As water is produced out with the produced
fluids, it gets processed and re-injected all back into the
reservoir for pressure management.
4:30:18 PM
A northeast slice of the reservoir through the southwest
revealed the same volume of gas cap as in the oil rim, a massive
amount of reservoir pressure sitting on top of the oil. If you
drilled a vertical well down through this part of the reservoir
Mr. Digert said, you would basically hit oil and gas and not
much else. This is called the gas cap area. In the main part of
the reservoir you would drill down and find some gas, but you
would also find a very large oil column called the gravity
drainage area. Farther to the south is an area where all you
would hit was oil and that is what they use as their water flood
area.
4:32:30 PM
He explained that a couple of different methodologies and
technologies are employed to produce the oil. In the gravity
drainage area the gravity drainage itself is used to produce the
oil. The gently dipping structure was exaggerated in the
cartoon, but it actually dips at about 1-2 degrees so the oil
actually drains downhill and gets produced at the bottom - the
pressurized gas on top pushing down on the oil to the producing
wells.
MR. DIGERT said the gas cap area has some oil. Originally, the
reservoir was much flatter and was filled with oil. When it
tilted, it left some oil behind in the gas cap. So, if they re-
inject their lean gas up there in addition to supporting the
gravity drainage mechanism, they get something called lean gas
injection that vaporizes those remaining barrels that are very
low saturations and produce them as well.
MR. DIGERT said a lot of technology is used with water flood not
just in injecting but what they add to the water. Can they
inject into different layers or inhibit the more permeable
layers and force water to go into the less permeable layers. So,
they use a technology now called bright water, which is actually
a polymer that is injected out into the reservoir that goes out
with the water and reaches fairly deep into the reservoir
(1,000-1,500 feet) and then the polymer pops open and starts to
block off the preferential flow paths and divert the water off
into other flow paths and push more oil up and around it.
4:32:49 PM
The use of miscible gas injection was pioneered at Kuparuk;
initial patents were all filed around the Prudhoe Bay and
Kuparuk process. Having the gas available to use as miscible
injectant is very effective. At Kuparuk they use the water
alternating gas (WAG) technology that alternately injects water
and gas. The gas mobilizes the oil that has been left behind by
the water and the water comes behind it and pushes it out
towards the producing wells.
4:33:41 PM
Today the gas has moved down into the reservoir, but not in a
uniform manner. The shale zones are impermeable (water and oil
can't pass through them) and some of the gas has moved down
underneath and left oil sitting on top. In places where they are
injecting it tends to ride on top of those and leave oil below
the shale, and a very complex area in the center called the
gravity drainage water flood interaction zone has both things
occurring. So, both water and oil are intermixed with very thin
layers of oil.
4:33:58 PM
So, these days instead of having one well to the bottom of the
reservoir they need to go find the oil and that is very
difficult, because it is so intermixed now. A lot of technology
- seismic, drilling logging - is employed in finding it. They
are looking for oil up against faults or around shales that has
been left behind. And then use horizontal drilling technology to
put the bit into those unswept areas of the reservoir. In
Kuparuk they are now drilling targets that are around 10 feet
thick with remaining oil (with potentially a lot of gas on top
of it) in some places and wondering how to get below that. When
he left Alaska the first time in 1992, if the oil column was
less than 100 feet, they didn't even bother trying to drill
there, because it was considered sub-commercial.
Mr. Digert said in 1980 they produced 1.5 million barrels a day
from the field with a little bit of water and handled about 2.5
bcf/gas a day to produce that oil. By 1990 they were on decline
making 1.3 million barrels a day and producing a substantial
volume of water (from the water floods), and had increased their
gas handling up to about 7.5 bcf/day. By 2000, gas had further
expanded to the almost 9 bcf/day on peak days and oil was down
to 550,000 barrels with far more water being produced than oil.
Today, they are producing about 300,000 barrels of oil a day and
up to 1.2 million barrels of water a day, bringing and injecting
another 900,000 barrels of sea water that brings that up to
almost 2.1 million barrels of water a day. So, today they have
an oil field that is masquerading as a gas field, producing gas
with a lot of water that has a bit of oil coming out with it.
SENATOR MICCICHE asked as the oil gets thinner does it become
more technically challenging.
MR. DIGERT answered yes. By "thinner" he meant two things: some
of it is some oil remaining between thin layers of sand stone,
but typically that oil column is a small band of oil with either
gas or water sitting on top of it, both of which they will try
and comb through and preferentially produce the gas.
4:37:12 PM
He explained that when they first discovered the reservoir they
thought they had about 23.1 billion barrels of oil in place and
believe that is still accurate. With the technology they have in
place assuming they were going to cycle gas and re-inject it and
perform water floods, they expect it to produce about 9.6
billion barrels, a 42 percent recovery expectation. Today they
have produced 12 billion barrels, about 52 percent recovery.
They have hopes of getting up to around 14 billion barrels if
they can execute their 50-year future and that would exceed 60
percent recovery, which would be a phenomenal increase from
where they thought they would be initially.
To get here there they had several major advances starting with
water flooding in 1981, which required construction of two water
treatment plants, new injection wells and a pressurization
facility to pressurize the sea water, a series of gas handling
expansions (GHX) and another project to expand their MI with
another bcf/day. In 1986, they also started up a central gas
facility, which allowed them to go from 2.5 bcf/day to 3.9
bcf/day. This is also where they started making miscible
injectant and the NGLs which are blended with the oil and the
EOR process with the WAG cycles.
MR. DIGERT said all this EOR took a lot of continued investment
but it also allowed them to extend the field life substantially.
They originally built with a 30-year design standard and that
was passed in 2007 and they are still here sustaining those
facilities and working to ensure safe and reliable operations in
the future.
4:39:40 PM
In addition to the facility work, he said the initial wells were
completed in the first decades with well spacing of 160-acres.
Prudhoe Bay produced 1.5 million barrels a day and then they
doubled the spacing so they are now down to 80 acres per well.
Today BP is drilling to target "unswept zones," areas that
haven't drained effectively. Like at Kuparuk, most of those
wells are being done as side tracks with either a rotary rig or
coil tubing rig to try and reuse existing facilities, pad space
and flow lines. This has been a very effective focus.
4:41:13 PM
They also found a couple of decades into the field, the use of
rigs and coil tubing units and other non-re-activities for well
work became increasingly important, because they were very
mature aging wells.
MR. DIGERT said he would like to show them new activities and
facilities BP had built since 2007, but they don't have any.
They have not been able to find the right combination of fiscal
climate and production target to justify going forward with long
term investments at Prudhoe Bay. That 2007 coincides with ACES.
It's very difficult to go back and look at these sorts of long-
term investments - investing billions of dollars in water
expansion - because they pay out very slowly. So, their focus
now is on well work and rig activity, which has a relatively
short payout and allows them to continue to be cash flow
positive in today's environment.
4:41:49 PM
MR. DIGERT went to slide 7 that showed a 6 percent decline of
production at Prudhoe Bay Ivishak, but it would have been much
steeper (more like a 21 percent) without their rig activity. BP
is proud of the fact that they have been very diligent and
finding ways to innovate and bring on the additional barrels
through using rigs and existing technology.
SENATOR FAIRCLOUGH asked if the decrease in production every
July is because they are getting ready for the next season.
MR. DIGERT replied that was a good observation and the decrease
in activity is a combination of two things: their rates are
general lower in the summer because they actually make less
energy through their big compression gas turbines with warmer
temperatures, so they can't produce as much gas (their peak
rates are in the winter), plus that is usually combined with
turnaround at their facilities for maintenance.
4:44:54 PM
MR. BILBAO took up the presentation touching on what investments
looked like over the last six years or so for BP - excluding a
couple of items around mid-stream and the Liberty Project - and
broke it into capital investment each year between rates
sustaining versus rate adding. He said although their investment
had increased through 2008/9 their overall investment had been
declining since 2008 and before ACES their rig count was
approximately 10-12 rigs and that has dropped as low as 5 rigs
since then.
Today TAPS is three-quarters empty, he said. One of the issues
they need to recognize is that policy drives investment
decisions, which drive technological innovation. While the
producers control efficiency and technology, only the state
government directs fiscal policy and that is what allows the
opportunities to compete for investment, and those opportunities
must compete globally for that investment. There is not an
unlimited amount of investment available.
SENATOR MICCICHE asked if Liberty is a technology issue, a
fiscal policy or both.
MR. BILBAO replied that Liberty is a large technology challenge
and a challenge in other respects as well. What makes Liberty
different is that it actually sits in federal waters and is not
subject to ACES. So even though it is technologically challenged
it is still an attractive project that competes globally.
SENATOR MICCICHE asked if Liberty had been cancelled or set
aside for a brief period of time.
MR. BILBAO answered that the Liberty leases received a
suspension of production from the federal government at the end
of 2012; BP is evaluating the most efficient and technologically
appropriate manner for developing that resource and progress the
Liberty project appropriately next year.
SENATOR DYSON said they heard earlier that the state went to a
net profits tax with ACES hoping that being able to deduct all
the expenses would encourage people to go after the challenged
oil. At the time, Pedro van Meurs told them that the negative
thing they did was removing the incentive for more efficient
production, because the more efficient you get the more of the
total money is subject to taxes. If they figured out a way to
not penalize them for being more efficient, he wanted to know
what that would do to the decision process. They have also heard
that the permitting process takes five years and he wanted to
know how permitting impacts industry's decision process.
4:50:18 PM
MR. BILBAO said he was trying to stay focused on the committee's
request to focus on technology today and would write down his
question to respond to at another hearing, but basically they
look at the state's policy along with other factors and manage
their opportunities most efficiently and effectively within
that.
4:50:54 PM
MR. BILBAO summarized that BP is proud that it had been a member
of the community in Alaska for over 50 years and had invested
billions in development and technology advancements. They have
leveraged technology to exceed their original production
expectations, but it is becoming increasing difficult to pursue
the next barrel. Increasing production will need new long-term
technologies, and opportunities drive technology; and the policy
must insure it supports opportunity.
4:52:41 PM
CHAIR GIESSEL thanked him and invited ExxonMobil to offer its
perspective on what it will take to keep the Legacy fields
going.
4:52:51 PM
DAN SECKERS, Tax Counsel, ExxonMobil, Anchorage, AK, said they
support what the field operator said at about Prudhoe Bay and
Kuparuk. His perspective is that it is really in the state's
hands as fiscal policy makers to determine the future of the
Legacy fields in Alaska. He said Alaska has been and continues
to be a very important component of ExxonMobil's global
portfolio. They have had a presence in Alaska for over 50 years
and are the operator at Point Thomson, the largest working
interest owner in Prudhoe Bay and the lease holder of all the
known discovered Alaska gas. They are committed to Alaska and
its future and expect to be here for many years to come.
He said that ExxonMobil continues to support reforming ACES. The
need for Alaska to develop a competitive stable fiscal regime
that attracts the level of investments that the North Slope
requires is one of the most important issues facing the state.
The governor's four core principles that he emphasized in the
State of the State speech - that any reform of ACES be fair to
Alaskans, encourage new oil production, simplify and restore
balance to the fiscal regime to make Alaska competitive for the
long term - can form the foundation of a successful long-term
tax policy for the state.
ExxonMobil believes that the changes made to Alaska's oil and
gas tax regime since 2005 have had a negative impact on business
activity in Alaska and Alaska's overall investment climate. The
progressivity component of the ACES tax regime on top of an
already-high base tax rate creates a major disincentive to
invest in the high risk, high cost opportunities that are here.
These two features must be addressed for any tax policy to be
successful in meeting the state's desired production and long
term revenue goals, Mr. Seckers said.
Two aspects of the tax policy, however, are pro-development:
deduction of operating and capital expenditures before applying
the tax rates recognizes the high cost of doing business here
and the further tax credit for capital expenditures which
rewards those who invest in production and infrastructure. These
two components of ACES should be reflected in any revised tax
policy.
MR. SECKERS said he agreed with the state's own consultants that
Alaska has one of the highest and most punitive tax systems in
the world. It is essential that the tax structure encourage
long-term development of all its potential resources. He said
ExxonMobil values a predictable fiscal environment in which to
make long term investment decisions. Their capital investment
decisions are evaluated over decades and any change in the
fiscal regime has a direct impact on them.
Because of the nature and magnitude of the risk associated with
any oil and gas development coupled with the long lead time
generally required to recoup that investment, he said a stable
fiscal environment is key to any investment decision. Today
Alaska produces more than 16 billion barrels of oil from the
North Slope and there well over 5 billion barrels of known
resources remaining. These undeveloped resources represent a
substantial opportunity, but their development is at risk under
the current ACES system. Their production today is less than
one-third of peak production in 1988 and continues to decline.
4:58:44 PM
MR. SECKERS stated that industry currently invests well over $1
billion - a majority of which is in the Legacy fields - every
year just to maintain that North Slope oil production decline at
6-7 percent. Without that investment the decline would likely be
12-15 percent or greater. Without meaningful tax reform that
includes and applies to the Alaska's Legacy fields, Alaska can
expect production declines to continue. The Legacy fields not
only provide the majority of the state's revenues, they sustain
the current North Slope infrastructure and the operation of
TAPS, which are critical to enabling any new production. The
infrastructure from these legacy fields has already been
leveraged historically for satellite developments such as Point
McIntyre, Orion, Borealis, and other non-Legacy fields to
economically process and transport their oil from the North
Slope to refining destinations.
Without helping Legacy fields, he said the prospects of any
future new fields or development become even more economically
challenged and make the probabilities of Alaska reaching its
desired goal of long-term sustained production levels that much
more difficult. Encouraging increasing investments to keep these
Legacy fields healthy is therefore as important as encouraging
investment in any new field or development.
MR. SECKERS said emphasis has been placed on making Alaska
competitive relative to other regimes, but that is only part of
the overall picture. Benchmarking government take against other
producing areas also is a very useful tool for gauging basic
competitiveness, but it doesn't provide the full picture of
investment health. The majority of the spending on the North
Slope has been for maintenance of existing operations not new
development. The state simply has not attracted the new
investment needed under ACES.
Complicating Alaska's production decline are its high
exploration, development and production costs. It is one of the
most expensive places in the world to develop and produce oil
and gas and a stable tax structure would allow and encourage
investment and ensure a corresponding opportunity for upside
potential. Upside factors such as increased production and
higher prices can compensate for the risk taken by investors
because companies are certainly negatively impacted when lower
than expected production or prices occur. High marginal tax
rates under the progressive structure of ACES takes away the
upside potential and reduces the attractiveness of those capital
intensive investments compared to other locations where the
upside benefit of investments can be retained.
MR. SECKERS said that ExxonMobil recognizes the state's
difficulty in tackling the it's tax policy while protecting the
current revenue streams and addressing the revenue problems just
over the horizon as production continues to fall. In many cases,
today's production rates are a result of government policies,
technical work and investment decisions that were made decades
ago. Increasing production rates in the decades to come will
result from sound policies, decisions and commitments that are
made by this legislature.
5:04:31 PM
He reiterated that ExxonMobil is committed to Alaska and fully
supports the governor's and this legislature's efforts to reform
ACES and to make Alaska's investment climate globally
competitive. Alaska needs a long term resource policy that will
encourage increasing investment in all remaining resources that
are economically challenged both in new fields and in existing
and particularly Legacy fields. The reform needs to create a
balanced program using a combination of changes to
progressivity, the high base tax rate and capital expenditure
tax credits to provide a competitive balance of government take
across all prices bands.
MR. SECKERS said ExxonMobil looked forward to working with the
administration, this legislature, industry partners and people
of Alaska to pursue the development of Alaska oil and gas
resources.
CHAIR GIESSEL found no questions and thanked Mr. Seckers for his
presentation.
5:06:56 PM
There being no further business to come before the committee,
Chair Giessel adjourned the Senate Resources Standing Committee
meeting at 5:06 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SRES BP Presentation Bilbao Digert 2013.02.08.pdf |
SRES 2/8/2013 3:30:00 PM |
|
| SRES ConocoPhillips Testimony Jepson 2013.02.08.pdf |
SRES 2/8/2013 3:30:00 PM |
|
| SRES ExxonMobil Testimony ACES - Alaska's Investment Climate Seckers 2013.02.08.pdf |
SRES 2/8/2013 3:30:00 PM |
|
| SB 26 Written Testimony RickRogers Resource Development Council 2013.02.06.pdf |
SRES 2/8/2013 3:30:00 PM |
SB 26 |
| SB 26 SEACC Summary-Fraser Institute Annual Survey of Mining Companies 2011 2012 2013.02.07.pdf |
SRES 2/8/2013 3:30:00 PM |
SB 26 |
| SB 26 Supp Letter MichaelSatre Council of Alaska Producers 2013.02.07.pdf |
SRES 2/8/2013 3:30:00 PM |
SB 26 |
| SB 26 Written Testimony HalShepherd Center for Water Advocay 2013.02.06.pdf |
SRES 2/8/2013 3:30:00 PM |
SB 26 |
| SB 26 Water Reservation Applications By A Person 2013.02.08.pdf |
SRES 2/8/2013 3:30:00 PM |
SB 26 |
| SB 26 DNR Responses to Cmte Questions 2013.02.08.pdf |
SRES 2/8/2013 3:30:00 PM |
SB 26 |