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How Technology Increases Oil Production
Posted by Phil Hart on July 17, 2008 - 10:00am in TOD: Australia/New Zealand
Topic: Supply/Production
Tags: eor, indonesia, oil companies, original, reserves, technology [list all tags]
How can you double something and still have ten times less than you started with?
| The answer to this question will help us reassess claims that advances in oil field technology will postpone the peak in global oil production. The question itself arises from a case study of Enhanced Oil Recovery in the Handil Oil Field in Indonesia. |
The Handil Oil Field
Handil is a giant oil field in the Mahakam Province of Indonesia, discovered in 1974 and still operated by 'TOTAL Exploration and Production Indonesia'. The International Society of Petroleum Engineers had a feature article on 'Reviving the Mature Handil Field' in the January 2008 addition of their Journal of Petroleum Technology [1].
Figure 1: Location of the Handil Oil Field
Source: Wikipedia and LNGplants.com
From the JPT article:
- The Handil field comprises 555 unconnected accumulations (reservoirs) in structurally stacked and compartmentalized deltaic sands.
- The reservoirs are trapped by the Handil anticline, which is cut by major impermeable fault dividing the field into two compartments: north and south.
- The reservoirs are between 200 and 3500 metres subsea and cover an area 10km long by 4km wide.
API and Sulphur from this Handil Crude Oil Assay
Oil Recovery
Before proceeding, it is important to understand the basic mechanisms of recovering oil from a reservoir:
Pressure on the fluids in a reservoir rock causes the fluids to flow through the pores into the well. This energy that produces the oil and gas is called the reservoir drive [2].
Primary Recovery is the oil produced by the original reservoir drive energy. The two most important natural reservoir drive mechanisms are Gas Depletion and Water Drive:
- Gas Depletion Drive: In the subsurface, the oil is under high pressure and has a considerable amount of natural gas dissolved in it. When a well is drilled into the reservoir, pressure in the reservoir decreases and gas can bubble out of the oil which can form a gas cap. Dissolved gas drive is very inefficient and will produce relatively little of the original oil in place from the reservoir. While this drive mechanism is commonly used to produce gas fields, rarely would it be relied upon for oil production.
- Water Drive: Water Drive reservoirs are driven by water adjacent to or below the oil reservoir. The produced oil is replaced in the reservoir by water. An active water drive maintains an almost constant reservoir pressure and oil production through the life of the wells. The amount of water produced from a well sharply increases when the water reaches the well. The recovery of oil in place from a water-drive reservoir is relatively high.
It depends highly on the type of reservoir drive, the viscosity of the oil and permeability of the reservoir, but primary recovery produces on average 30-35% of the oil initially in place (OIIP), although it can be as low as 5%. Generally this leaves a considerable amount of oil in the reservoir, so additional recovery techniques may be employed:
Secondary Recovery: This involves injecting water into the field through injection wells. It can be initiated before or after the natural reservoir drive has been fully depleted. The aim is to use the water to sweep some of the remaining oil to producing wells. A waterflood can recover anything from 5-50% of the remaining oil in place that would not have been produced using primary recovery alone. The actual amount achieved depends enormously on the properties of the particular field.
Tertiary Recovery (Enhanced Oil Recovery): In some cases, where Secondary Recovery still leaves a significant amount of oil in place in the reservoir, enhanced oil recovery may be effective. Enhanced Oil Recovery (EOR) includes thermal, chemical and miscible gas processes - injecting substances into the reservoir that are not naturally found there.
Secondary Recovery techniques have been widely used since the early days of the industry. They are already in place in almost all fields where it is necessary or effective.
The history of Tertiary recovery also goes back more than half a century. Tertiary Recovery, however, is only effective for a narrow selection of fields and involves substantially higher costs and effort.
Lifecycle of a Giant Oil Field
In their 1986 assessment of the world's 500 "Giant Oil and Gas Fields", Carmalt and St John [3] ranked Handil number 303 with an estimated 800 million barrels of ultimately recoverable oil. We can see that this 20 year-old estimate is very close to the mark in terms of the amount of oil produced with primary and secondary recovery (see Table 2). This should give us increased confidence in the Carmalt and St John estimates for other giant fields, including those in Saudi Arabia and other OPEC countries where current data transparency is inadequate.
Figure 2: Handil Oil Production History
Adapted from this Presentation: Mature Kutei Basin of Indonesia
JPT: To maintain production and reservoir pressure, water injection was started in 1978 which maintained the 160,000 BOPD production until 1985.
The production profile here presents a common picture of the lifecycle of a giant oil field. Secondary recovery (water injection) is used to maintain an oil production plateau for as long as possible before more significant decline becomes inevitable. After that, owners of the field have to decide whether intensive efforts to study, develop and apply tertiary (enhanced) recovery will recover enough additional oil to make it economically attractive.
Mature Field Revitalization
JPT: In November 1995 a lean gas injection project was initiated in five reservoirs. The project boosted the production of the five large reservoirs and altered the overall decline rate of the field. Therefore, the project was extended in 2000 to six other large reservoirs, which resulted in more than 25 per cent of the field reserves being under a tertiary-recovery mechanism.
Tom Standing (ASPO USA Newsletter, November 5, 2007):
Oil extraction by miscible gas injection goes beyond conventional pressure maintenance by injecting a gas with specific properties, at pressures sufficient to create a highly mobile gas/oil fluid phase that swells and fills pore space in the reservoir rock. Compression energy from the surface pushes this miscible phase toward wellbores. Injected gas cannot be chemically reactive in the reservoir.
Of the 8 million barrels produced using enhanced recovery mechanisms up to 2002, 6 million was from Phase 1 Lean Gas injection and 2 million from Phase 2 Lean Gas injection. Spurred on by their early success with lean gas injection, TOTAL kicked off a bigger campaign of 'Mature Field Revitalization' in 2003, including the following activities:
- Dynamic Modeling and Sweet Spot Mapping: Dynamic computer models combined with well logs and other static historical production data are used to identify the location of bypassed oil and smaller undrained areas of reservoir.
- Light Workovers (LWOs): Well interventions performed without pulling the completion at the bottom of the well. These LWOs are used to isolate water producing zones and target prospective new reservoir sections.
- Infill Wells: Where a Light Workover cannot be used because of the condition of the well, drilling new wells recovers the potential reserves in areas identified by Sweet Spot Mapping.
- Enhanced Oil (Tertiary) Recovery and Optimization: Miscible Gas Injection (described above), in this case using natural gas, is injected into the crest of the reservoir and attempts to sweep oil that has been bypassed toward the producing wells.
JPT: In 2005, 26 LWOs were performed, of which 19 were successful. The project resulted in 1.7 million STBO (stock tank barrels of oil) production during the year and 4 million STBO of incremental reserves. The total cost was approximately USD 2 million.
The stated costs for LWOs yield a figure of $2 per barrel added as reserves - very economical but the potential is of course very limited (production costs are in addition to this). The more expensive infill wells were used for shallow reservoirs with heavy oil, or multi-lateral wells to target multiple small reservoirs which did not justify single wells previously.
The Results
Hopefully it is clear that what is simply described as 'Mature Field Revitalization' comprises many years of technically challenging study and modeling followed by intensive application in the field. For the engineers and geologists involved this was no doubt rewarding work. While all of these activities can be considered the application of 'new technology', only the final step is considered Enhanced Oil Recovery.
JPT: These key elements increased the production from 12,500 BOPD in 2003 to 23,000 BOPD in 2007.
For a substantial investment of time, money and effort in the giant Handil oil field, we gain just 10,000 barrels per day of oil production. Yet this case study has appeared in the Journal of Production Technology because it is a prime example of what can be achieved (the two other case studies in the same issue showed only very mediocre gains). While there will be isolated fields that perform better, there will be many more that fail to make the pages of the Journal of Petroleum Technology because they provide far less spectacular returns. In many cases, after intensive appraisal and assessment the schemes never get off the drawing board.
Tom Standing (ASPO USA Newsletter, October 1 2007):
An aspect of EOR that is seldom discussed is that recovery processes target oil fields with highly specific properties of reservoir rock and fluids. In brief, EOR processes are not universally applicable. With long years of research and field trials, the industry has developed two categories of EOR success.
- Thermal methods in highly permeable reservoirs containing heavy viscous oil
- Carbon dioxide or nitrogen (or natural gas) injection at miscible pressures in reservoirs with poor permeability
The vast population of oil fields with light oil and good permeability generally have not responded to EOR efforts [because Secondary Recovery alone is already highly effective].
The Impact of Technology
TOTAL would be pleased if their efforts with the Handil oil field can increase the ultimate amount of oil recovered by even 5% (40 million barrels) compared to primary and secondary recovery alone. A 10% increase in this case looks unlikely. The returns look pretty small when averaged across the world's oil fields, given that only a proportion of them deliver a reward for this kind of effort.
While these aspects of 'advanced oil field technology' can increase production from particular oil fields, thereby attractively increasing profits for the owner, they do not significantly alter the picture of global oil resources.
Figure 3: World Oil Discovery and Production
The Law of Diminishing Returns
Economists seem to have trouble understanding geological and technical limits to oil production, but they should understand the law of diminishing returns (Wikipedia):
According to this relationship, in a production system with fixed and variable inputs, beyond some point, each additional unit of variable input yields less and less additional output. Conversely, producing one more unit of output costs more and more in variable inputs.
In our case we have finite, bounded oil fields. Until the mid 1980s, discovery of new oil fields exceeded our consumption rate, so there was little need to increase recovery from existing fields. As the discovery rate declined, companies had greater motivation to extract more from their existing fields. While at first they found easy gains, in the last decade especially the amount of effort required has climbed and yet the returns are falling: is it any surprise that oil industry inflation is rampant?
Oil field reserves may have 'grown' 10-20 per cent since the Carmalt and St John assessment in 1986, but we should not expect the next 20 years to deliver the same gain. Discovery of new fields has tapered off to low levels and the easy pickings for increased recovery have already been had. Unconventional oil sources will yield similarly small returns for extraordinary amounts of effort. The numbers simply do not stack up for oil production continuing to expand for another decade against the decline in large mature conventional oil fields.
Summary
How can you double something and still have ten times less than you started with?
In the case of the Handil Oil Field, a concerted campaign to revitalize the field almost doubled production from 12,500 barrels per day in 2003 to 23,000 in 2007. Yet this field had once produced nearly two hundred thousand barrels per day.
This is a representative picture of the role of technology and enhanced oil recovery: merely extending the tail end of production in oil fields that are well past their own peak in production.
So while the Society of Petroleum Engineers and other optimists tell us that technology and enhanced oil recovery will delay peak oil, a more objective look at the data suggests that production declines are relentless and they are stacking up much faster than incremental technological gains.
Contact the Author or download this article as a PDF.
Try these tags for other relevant articles at The Oil Drum:
Enhanced Oil Recovery
Technology
and don't forget HO's wonderful Tech Talk series, which has just about every resource production and extraction topic one can think of.
References:
[1] Denney, D. "Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application", Journal of Petroleum Technology, Society of Petroleum Engineers, Houston, January 2008.
[2] Hyne, Norman J., "Nontechnical Guide to Petroleum Geology, Exploration, Drilling, and Production". PennWell Corporation, Tulsa, Oklahoma, 2001.
[3] Carmalt, S. W., and St. John, B. "Giant oil and gas fields," in M.T. Halbouty, ed., Future petroleum Provinces of the World, Memoir, 40, AAPG, Tulsa, Oklahoma, 1986.
[4] Mature Kutei Basin of Indonesia: http://www.ccop.or.th/PPM/document/SEM2/Indonesia.pdf
Very interesting article. There was a lot of hype about advances in Oil Extraction Tech, like "...extended reach and horizontal drilling, advanced sand management, expandable screening and/ or electrical submersible pumps, drilled with minimally invasive drilling fluids, tight control of equivalent circulating density and high-precision geological optimisation of well placement"... We now know from the Handil Oil Field example, that there are huge limitations on how much extraction can be ramped up.
It will take a few more years for the reality to set in. We need someone to continuously challenge the MSM on this... :D
Way off topic:
Can somebody link me to a graph/chart/diagram showing net electricity import/export by state for the US? I can't google what I'm looking for well enough. Thanks.
I think you'll find what you're looking for in Gail's post here: http://www.theoildrum.com/node/3934 on the grid. If not, try the EIA.
Excellent and very clear article! I particularly like the scale question "How can you double something and still have ten times less than you started with?".
Scale is what people have most trouble with in regards to PO, there are plenty of examples:
Again, as I have stated before, I'm not saying to despair or that there's no hope - just that many people who I still talk to after several years refuse to understand the potential gravity of the situation due to the scale of it.
There's always something 'out there', whether EOR, not-yet-found-supergiant-fields, reserve growth or whatever, that will save the day. Something will 'come along' and 'save us'.
I find this type of betting on a positive black swan not only intellectually naive, but also potentially very irresponsible.
That is why I thank you for providing a clear and concise explanation for the likelihood of EOR 'saving us'.
We need more like this.
"merely extending the tail end of production in oil fields that are well past their own peak in production."
As a petroleum engineer I understand this better than the average person on the street. However the problem is in the lack of understanding of what "advanced technology" means as applied to raising production ( the magnitude and the point in life cycle of a field). This leads many to think that it will lead to solving our problems with production needed to meet current demand.
The real problem is the diagram showing the growth in reserves trend world wide. So far no technology that I am aware of is able to significantly change the trend we are observing now.
Good article !!!!
A student recently, and a colleague, sometime back, both brought me copies of Popular Science (or Popular Mechanics) with articles about how a new solar technology would solve all of our problems. They offered these as proof that everything would be fine. An awful lot of people read the popular media accounts of technology and believe these are the final words on the subject. It raises unrealistic expectations of what technology is, what it can do, and how it is developed.
The article points out an incredibly important issue - the law of diminishing returns. This law not only applies to marginal oil recovery per unit of energy consumed, it also applies to technology development itself. The vast majority of technological development is marginal improvement. Occasionally we get lucky and find a new physics principle (e.g. solid state electronics) that allows something like a quantum leap. But you'll note that this seems to apply to information technology more than production work. IT can be applied to production work to gain some marginal increase in efficiency (e.g. using robots to make cars). But processes that do useful work don't come under the miracle of Moore's Law (we have yet to see how nanotech machines will be applied to large-scale production work).
In the west we suffer from the innovation myth. We've seen so much innovation in one particular area - digital solid state electronics - that we transfer that observation to apply to all technology. And so, many people lack critical judgment when it comes to assessing the efficacy of technological solutions. Sadly this applies to politicos and policy makers (e.g. corn ethanol) as well as the general public. And sadly, it will be a block to a deeper understanding that would allow us to make real progress.
George
I bet you're thinking of A Solar Grand Plan: Scientific American. PV with storage in NG fields nationwide. Don't think many tech breakthroughs would be called for but gawd! what a monstrous amount of buildup. It's been hashed over here, do a search. And there have been a few other Grand Solar Plans proposed here, like Staniford's.
Innovation and scalability are the two things people just don't understand. What we need are short-and-sweet illustrations of the size of these hurdles. People can't grok page after page of reasoned documented arguments, they need something that they can take home, that can't be forgotten readily, like 1000 barrels a second or a cubic mile of oil.
If you check the comments on the Solar Grand Plan, you will see that it was pretty thoroughly disembowelled.
Turns out they wanted to use compressed air as the storage medium, and the process they suggested would use natural gas.
That would involve more NG than is likely to be available, apart from it's global warming implications.
Solar has a big contribution to make in providing peaking power, but even at the latitude of the Mohave winter incidence is only around 25% or so of that in the summer, so that you would need a massive overbuild to provide base-load.
That passes over the fact that you would also need to have dry cooling, which is expensive as it is a water-stressed area, and ignores the fact that even providing enough storage for overnight power is not easy or cheap.
Solar thermal is also dependent on really clear skies, far more than, say, amorphous silicon, so that back up power is also needed for up to a week, even for the Mohave, as I was informed by someone in the industry.
As for schemes to power the whole country this way, let alone run Europe from transmission lines from the Sahara, they are pure science-fiction.
PV power locally produced is a far better bet, although very expensive for the moment.
Anyone catch Al Gore's speech today? I'd really like to know who his energy advisers are. Maybe the same guys who wrote that SciAm article. I did read it and at the time just shook my head.
I actually designed and built solar energy systems back in the 80's. HUD sponsored demo projects and a few private projects. In fact that is how I got into computers - designing some of the first µ-processor based controllers for solar collection. I got out of the business when I realized that it probably took more total energy to make the glass, aluminum, copper, and urethane insulation, manufacture and deliver the collectors than the systems ever delivered to point of use. For the home owner - energy savings. For the nation - net energy loss.
In Gore's speech he emphasized the connectedness of energy, climate, and economics which was good. But in most of the proposed solutions I fail to see whole systems thinking being displayed. I also realize that the vast majority of people simply do not intuit the second law of thermodynamics. They don't grok ERoEI, or any of the real physical constraints that dictate energy engineering.
Scale and rate of construction of whole systems. I wonder what it will take to get people to think this way?
George
Just to echo your point SamuM,
A simple calculation with Excel shows that we will have to build roughly 16 one Gigawatt nuclear power plants (1-GWNPP) per year to compensate for just a 2.5% drop off after peak oil. For you trivia fans, a 1-GWPP produce roughly the same amount of energy per year as in 4.5 million barrels of crude. An interesting highlight of this is that in just 3 years, we would have to build roughly the same number of power plants and Senator McCain is proposing to build by 2030 as part of his comprehensive solution to the energy crisis. A 4.5% roll off requires around 75 1-GWNPP/year or roughly 1 1/2 per week. I think I'll go take my Zoloft now.
Said by Stephen Hubbard:
The comparison of the energy from different sources is not this simple because one must consider the efficiency when it is used. Although I do not know the enthalpy of combustion of crude oil, assuming electricity is to replace 4.5 Mb of gasoline to power cars, I get:
enthalpy of combustion of gasoline: 130 MJ / gallon
130 MJ/gal * 4.5 Mb * 42 gal/b = 24.6 x 1015 J
Because an electric car is 3 times more efficient than a gasoline powered one, this translates into an electric power plant operating continuously for a year with a power of:
(24.6 x 1015 J/year / 31,560,000 s/year / 3 = 260 MW
Edit: The CAFE Formula, Forum on Physics & Society of The American Physical Society, David Hafemeister, v36, n4, October 2007; states an electric car is 5.4 times more efficient than a gasoline powered one making my calculation too high.
This is also a good example of the depletion rates of fields using modern methods.
Looking at the graph it had significant production for about 10 years from 1977 to 1987.
Or about a 10% depletion rate. Then a steep drop at whats actually about 90% overall depletion
and a long decline at a much lower production rate. About 30% or less of the original rate.
Now whats important is that to replace this field one would have to find a field of the same size about
every 10 years.
You can keep overall production the same if you find 4 fields smaller fields but these tend to have shorter life times and are less economic to redevelop using advanced extraction methods. If the field is to small even secondary extraction may not be attempted.
We have thousands of fields like this in production right now that are approaching the end of their ten year primary production life.
In general we have no new discoveries to replace them. To keep production close to our current rate we would have had to find and develop enough fields within the ten year periods that our current smaller fields produce at a high rate to replace them.
For simplicity you can assume all the small fields where brought into production at t0 and at t10 ten years later you would need to have 100% replacement.
As long as new discoveries can be found and brought online fast enough oil production remains fairly level but once you pass the point that no new discoveries are made in significant numbers then about 10 years later all of the smaller fields will be in significant decline.
From the graph you have 10% of production from fields less then 10 years old but you can see that discoveries have dropped to a low level since about 1985. And most of this 10% only has a high productive life span of 5-10 years.
It should not be hard to see we are entering a time that 10% of our current production from a swarm of short lived smaller fields has a good chance of going into a steep decline dropping by 60% over a period of 1-3 years.
So in my opinion our immediate problem is not the slower declines of the giants and super giants with production life times that span decades but declines from these smaller fields from lack of replacement.
Once they are gone the decline will moderate to match the slower decline rates of the larger fields.
you fail to mention, as a significant drive mechanism, good old mother nature. i.e. gravity drainage. what is the typical reservoir dip angle on this field ?
i agree that eor has limited benifit in this case, because of the relatively high (gravity aided) secondary recovery. too few people grasp the concept of material balance, which in it's simplist form simply states that the amount of oil remaining is equal to the original amount minus the amount produced.
this sounds like a very complex reservoir, without some additional data, i find it hard to believe that secondary recovery could be in the 70% range without a significant gravity drainage contribution.
i know of examples where similar recoveries were obtained by waterflood, but guess what - steeply diping reservoirs. and not that good of reservoir properties, with the exception that the oil being of high gravity thus low viscosity.
memmel keeps banging on the theme that smaller fields can't replace bigger fields (which i agree with) and i keep banging on the theme of gravity drainage.
the percentage production figures are proportions of the total oil produced up to 2002, not percentage recovery of oil initially in place. you are right - recovery of oil in place in this field will not be anywhere near 70%.
gravity drainage will also not be significant for this field!
sorry, i guess i missed that part. what is the recovery % of ooip ?
sorry to disappoint, but recovery factors are not available in the JPT article. you'd have to ask somebody working for TOTAL in Indonesia..
Gravity drainage fields can really confuse the villagers. I have one such fld that has produced for 50 years (20 mmbo so far) and will produce for another 100 years (maybe another 20 mmbo). When the angry villagers hear such tales they begin to think there really is help out there for them. The wells in this field make about 1 bb/ per day. It obvious has no bearing on PO. But the little ma and pa operators are slowly becoming millionaires.
But what compounds the confusion are the public claims by oil companies regarding the great profitability of EOR these days. Those optimistic statements are valid with regards to the company's financial future but have a minimal impact on PO. The villagers will see many press releases from the public oils rightfully touting the profits of additional exploration and EOR. And we should count on these angry villagers to take those press releases as a sign that there really isn't a big problem with PO.
BUT: EOR and more exploration will delay PO. That's a point of logic that cannot be denied. But whether it delays it 5 years or 5 months is the question we can bounce around just for the fun of it. My guess would be NOT 5 years.
What are the rate laws that affect gravity drainage? Is it a first-order diffusional law, something akin to Fick's law? In that case, you will see a fractional power-law growth in cumulative reserve (specifically a square-root law if you work out the math) and the reciprocal of this for extraction. This kind of behavior does show the long tails you would see.
I suppose you can provide a more detailed analysis, but this kind of first-order look can provide a lot of context for those of us that come from different areas of expertise.
the basic's of gravity drainage are contained in d'arcy's law which stated mathmatecally is:
v = c(k/u)(dp/ds)
with a substitution v=q/A then c becomes 1.127 (usually presented with a minus sign, because dp/ds is negative)
where q is in bbls/day
and A is the x-sectional area of flow, sf
k, permeability, is in darcies
u, viscosity is in centipoise
dp/ds is pressure drop, psi/ft
for the case of gravity drainage dp/ds can be taken as (dp/dh)*(dh/ds)
dp/dh is the bouyancy of the oil or difference between the fluid gradient for oil and water, psi/ft.
= 0.433 (rhowater-rhooil), at reservoir conditions.
and finally dh/ds is the change in elevation over a distance. or simply sin dipangle.
and strictly speaking d'arcy's law only applies to single phase isothermal flow under steady state conditions. and for cases where the capilary pressure is zero(well above the oil/water contact)petroleum engineering usually makes lots of assumptions, so these restrictions are usually just ignored.
So this is actually Fick's Law of diffusion!
This in fact is very simple to solve. I have done a post on this behavior before (http://mobjectivist.blogspot.com/2006/01/grove-like-growth.html) and in actuality diffusion and dispersion are the same sides of a coin so it follows the same trending of the Dispersive Discovery curve.
Take the equation for d'arcy's law
v = c(k/u)(dp/ds)
and then substituting (dp/dh)*(dh/ds)
The key is the dh/ds term, the dipangle. The ds is essentially a displacement in volume as the gravity drainage starts to move material from one volume to the other. So whatever goes from one side of "s" goes to the other side, the "v" side. This means that the length of the partially drained volume gets bigger and bigger with time.
Look at the width in the following figure where x is the s term:
So x or s gets bigger and bigger with a cumulative increase proportional to the integral of v. With the small sin approximation for sin (dipangle) you get dh/ds = h/s
so rewriting this, replacing U with s to denote cumulative volume
dU/dt = k / U
this solves simply as U(t) = k * sqrt(t), which is Fick's Law. The bottom-line is that you get progressively diminishing returns over time.
Very good article. I like to apply what we learn from individual fields and apply it to a larger scale. In this case you can almost think of individual fields as Kroneker delta discovery function (the initial impulse) followed by a unit step function of lower rate that lasts for X years (the reserve growth).
If you scale the delta and unit step function just right, and then apply a convolution of a damped exponential (the extraction rate) to this stimulus, you arrive at something that looks quite like what you see.
If the unit step is lower in scale, then the initial decline sets in immediately, and the top plateau is not flat. And if you replace the delta and unit step with 2 declining exponentials of different shapes, then you end up with a 2nd order gamma function, and the whole profile looks smooth.
These components are what I refer to as "shocklets" and can be used to build up a macro model from the micro model we see on individual oil fields. The macro view is actually the heart of the Oil Shock Model that is often discussed on these pages. But sometimes it is good to see how this stems from the results on individual fields.
And a note to all the EE's and ME's out there: this stuff must look awfully familiar as the process mimics the analysis of linear response functions from an input stimulus.
thanks WHT
I just sent some of your stuff to a friend and maths lecturer at Latrobe Univeristy in Melbourne who will hopefully be using it as lecture material:
http://johnbanks.maths.latrobe.edu.au/
Phil,
Great article. One aspect about technology applications leaves me uneasy. The use of technologies to enhance production can fall into two types. One type is to improve production rate of an existing reservoir, produce what is there faster. Examples may include horizontal or multi-lateral wells. The second allows recovery of OOIP that would otherwise be missed, recover more of what is there. This may be like you cited, water sweeps or enhanced recovery. In the real world it may be some combination of the two.
Nominally if we refer to something like the Hubbert curves for production, the second type of technology increases the total volume under the curve. However the first technology influence only increases the height, but shortens the base of the production profile. It may also tend to skew the profile non symetrically into higher peak but more severe drop off on the down side.
I have no hard numbers but my gut instinct is that most of the technologies applies over the last 20 years have been to boost the production rates and maximize short term returns for the oil companies. While there have been advances in the improvements of recover factors, this is probably small compared to the improvements in the recovery rates. If we equate this to technology equivalents of production and discovery where production is the faster recovery and discovery is more effective recovery, we are "producing" faster that we are "discovering".
You must take into account that increasing the flow rate will help keep companies from abandoning a reservoir, altough I am not sure if that will hold after peak oil.
You're quit right about "boosting the production rates and maximize short term returns for the oil companies". Essentially oil patch economic decisions are dominated by “net present value”. NPV adjusts the cash flow to take into account the time factor. A fld producing 2 millions bo over 20 years has a much lower NPV than a fld producing 1 mmbo over 4 years. The common discount rate is 15%. Think of the DR as the interest rate on a loan. A 15% loan paying back $1.15 in one year would have a NPV of $1 and thus no profit would be made. The NPV factor is used to determine the rate of return on an investment. The stock market demands y/y improvements in a public company’s position. As odd as it may seem virtually all public corps would chose a high NPV approach to development over a low NPV approach even if it produced a greater ult recovery. NPV is especially important in those big Deep Water plays. During those long development phases (6 to 10 years) that 15% keeps compounding. If you look at the decline curves of the initial Deep Water Gulf of Mexico flds you’ll see high initial rates and relatively rapid declines. This is a design option chosen by the operators. You’ve heard it before: Time is money. And when you’ve sunk #1.5 billion into a project before it flows the first bbl of oil that time is very expensive.
On horizontal wells, they can also add significantly to ult recovery sometimes. I can’t recall a specific example but an increase of 20% or more is possible. But this would be a very field specific number. Another fld might only show a few percent increase. But you’re definite right about changing the decline curve significantly for many water drive reservoirs. Vertical wells are produced thru holes shot in the casing. In a water drive reservoir (as most big oil flds are) the water moves upwards as the oil is produced. If you have a oil sand 100’ thick you could just shoot holes in the top 1’. That would delay the water cut as long as possible. But you’re not going to flow much oil thru 1' of perforations. At the other extreme you could perforate all 100’ of the reservoir and get the maximum flow rate possible. But you would also start producing water almost immediate because you shot down to the water level. This would greatly reduce you ult recover from that well.
A horizontal well provides the best of both worlds. A 100’ long horizontal well in the top 1’ of a reservoir would have a very high flow rate but it takes a much longer time for the water to reach that top 1’. This greatly enhances ult rec. The well would also show a rather low decline rate for a long time. But imagine when the water level finally reaches that top 1’. That well could go from a great commercial producer to marginal in just months. It was reported that Saudi spent over $10 billion in the late 90’s drilling horizontal wells in Ghawar Fld. This would have given a big boost to flow rates and they would have shut in the high water cut vertical wells. This is the really scary aspect in estimating Ghawar’s future decline profile. I have no guess to how much of production today is from hz wells vs. vert wells. If the hz wells are the great majority the decline curve could have that big cliff drop off you describe...
and not be too many years down the road. And a company can easily monitor where the water level is at any one time. Saudi has a good estimate of when the SWHTF in Ghawar Fld but they're not sharing.
Very interesting (and scaring) comment. I have several questions:
"NPV is especially important in those big Deep Water plays." As oil exploration is increasingly moving to deep water this means that we have to expect that the recovery ratio won't increase but decrease compared to good old onshore fields, right?
As for the vertical wells: I know that in groundwater wells packing seals can be used to decrease the area of water inflow. So theoretically one could perforate all 100’ of the reservoir, and as soon as water seeps in stepwise reduce the inflow area to the upper part. Is this possible with oil wells?
Phil, a fascinating article which has had me glued to the flatscreen. Thanks.
One reservation. You write that “the two other case studies in the same issue [of JPT] showed only very mediocre gains”.
Well, I suppose that depends on what you call ‘ mediocre’. One of the two other studies concerned a Malaysian oil field (‘Betty’) and the results seem pretty good to me unless I’ve misinterpeted the data.
Here’s an extract from the conclusions of the Betty field production-enhancement study (page 62):
13% is quite impressive and 5 million barrels isn’t small fry!
Thanks. I was looking at the absolute production increment achieved in the other two fields. A few thousand barrels per day of extra production is not much to get excited about.
But you make a fair point.. i obviously didn't read them carefully enough (my head was buried in the Handil pages for long enough!). The other two articles are very short on important stats, which led me to think their story was not as convincing.
On Ecopetrol's Yarigui-Cantagallo field in Columbia, production was increased from 5,000 barrels per day in 2003 to a peak of 12,000 barrels per day in 2006 but declining again after that. Previously, the field peaked at 20,400 BOPD in 1962, after first development in the 1940s. Their EOR efforts appear to have added more than 25 million barrels of oil as reserves, but that still looks to be only about 10-15% increase.
For the Betty field in Malaysia, there's more detail here:
www.china-drilling.com/spe2006(beijing)/spe101491.pdf
The percentage increase in reserves due to EOR for these other two fields may be higher than Handil, but the absolute returns are a lot less. With smaller fields, you need a bigger percentage return to make it worthwhile. With a larger field, a few extra percent may be worth the effort, but there are nowhere near enough fields as large as Handil for us to add enough to total world reserves.
So in each of these two extra cases, we're talking about production increases of just a few thousand barrels per day. In terms of reserves increases due to EOR, we've got less than 10% in Handil, 13% for Betty and something similar in Yarigui-Cantagallo. And this is three of the best!
By the time you average that across all the world's all fields, with most returning even less (if anything), the typical return for EOR is well under 10%! That's not going to save us.
And I just found an electronic copy of the whole section of the JPT on which all of this was based so now everybody can read all three articles for themselves!
www.spe.org/spe-site/spe/spe/jpt/2008/01/2MatureField.pdf
princesses are turning into pumpkins here in oz, so lights out for me for awhile.
hopefully you can help me out with a few votes at digg/reddit and your other favourite hiding places:
http://digg.com/general_sciences/How_Technology_Increases_Oil_Production...
http://www.reddit.com/info/6s7my
http://www.reddit.com/info/6s7op (technology section)
thanks!
Isn't that a really awful example of EOR-CO2?
OFFSHORE EOR-CO2 is still a NEW technology!
Look at Weyburn instead.
It has produced 350 million barrels of oil so far and with CO2 Schlumberger expects to produce another 130 million barrels. Beyond geology, the difference may be a huge steady source of CO2, the Beulah syngas plant in North Dakota.
http://www.seed.slb.com/en/scictr/watch/climate_change/weyburn.htm
IMHO, all you've proven is that different sites and different manners of development produce different results.
This presentation from Schlumberger gives some info on costs involved.
http://www.conferenceworld.com.au/resources/other/Dr%20Geoffrey%20Ingram...
When I first read your piece I thought you were stating facts--but your post is just negativity and premature defeatism. I hope it's not deliberate.
Sheesh!
majorian,
You're very right about the field specific nature of all EOR projects. Beautiful ponies and ugly dogs. And sometimes not too far from each other. Are you asking if offshore CO2 EOR is a new technology? CO2 injection projects have been around for many decades. But not very common offshore due to the logistics involved. Otherwise it’s pretty much the same process. An alternative to CO2 in nitrogen injection. Not quit as effective but can still work. And N2 can be produced right out of the air. Mexico’s huge offshore field Cantarell has the largest N2 generating plant in the world. They’ve used the N2 to maintain reservoir pressure to increase flow rates and ult recovery.