technology and decline rate

8/14/2019 Technology and Decline Rate

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DEPLETION: THE FORGOTTEN PART OF SUPPLY AND DEMAND

By Matthew R. Simmons, Simmons & Company International

While there are hundreds of published forecasts on the supply and demand for oil, some

extending all the way to the year 2020, the industry has no published estimates as to the

average decline rate, or depletion of the existing supply base. Any knowledgeable

observer of the oil and gas industry knows that all hydrocarbon reservoirs ultimately

begin a production decline. Many small fields only maintain peak production rates for a

short period of time before steep decline begins. Yet no one produces reliable field by

field decline estimates, let alone even makes a guess at the current blended rate of for

the worldwide production base of oil and gas.

The issue was not particularly serious for years when a high percent of the worlds oil

and gas production was coming from giant fields years away from beginning to

experience any decline. And, when the world had tens of million barrels per day of shut-

in capacity, decline rates were only relevant to the owners of a particular field.

Today, the world of oil and gas is quite different. The amount of shut-in capacity is, at

best, only three to four million barrels per day, less than 5% of present demand. An ever-

increasing percent of the world production base now experiences high decline rates,

particularly if a massive amount of added development and workover activity is not done

to slow these declines. Moreover, a large number of the giant older fields which anchor

the worlds hydrocarbon production base have now started to decline.

As a result, it is becoming impossible to accurately predict the supply side of any oil or

gas forecast without dealing with the issue of depletion. And the rapid use of all the new

forms of oil field technology has tended to increase the decline rate of many fields, once

peak production has been achieved.

WHAT DEPLETION IS ALL ABOUT

All oil and gas wells exhibit declining oil and gas production over time, commonly called

depletion. As a well produces, the reservoir pressure typically drops, causing the


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production to decline. In many cases, artificial lift (gas-lift, rod pumps, electrical

submersible pumps, etc.) can extend the life of the well, but the production rate will

eventually decline below an economic limit and the well will be shut-in and permanently

plugged.

Wells producing from reservoirs with an active reservoir pressure maintenance program

also experience production declines once the injection fluid (usually water) reaches the

producing well. In many cases, the total liquid produced from these wells will remain

constant, but oil content declines as the fraction of water being produced

increases. The oil production declines because the amount of water in the reservoir

near the producing well(s) continually increases. This increasing water saturation

impedes oil flow into the producing well. The water does not completely sweep the oil

and as a result, a significant portion of oil is left behind in the reservoir.

In the early 1900s, the goal for many companies was to produce the oil out of the

ground as quickly as possible; a term we call blowdown production. As many wells as

possible were drilled, sometimes 10 wells per acre, which damaged the reservoirs and

significantly reduced the ultimate recovery. In these cases, the individual well and total

field rates were extremely high and declined off very rapidly in this blowdown

production mode. At the height of the development of the East Texas Field in the early

1930s, there were 12 wells drilled on 1/5 of an acre in Kilgore, Texas!

Eventually, regulatory authorities limited the number of wells drilled to typically fewer

than 16 per square mile (or 1 well per 40 acres). Usually the number of wells initially

allowed was far less than this and as the reservoir produced, the well density could be

increased as dictated by the effectiveness of the current well spacing and recovery

mechanisms. In this development scenario, the reservoir is developed over time with

new wells almost continually being drilled and adding to the overall field production. This

ongoing development activity masks field depletion as the new wells all or partially offsetthe decline form the older wells. The Prudhoe Bay Field on Alaskas North Slope

illustrates this.

Prudhoe Bay is a classic example of depletion. First, there is sufficient production history

to illustrate depletion. Second, high quality production data is available for the life of the


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field. Third, Prudhoe Bays operators have applied best in class reservoir management

practices. Graph 1 shows the monthly oil, gas and water production history from

Prudhoe Bay since start-up.

Graph 1: Prudhoe Bay Field Production History

Oil production was constant at 1.5 mmbopd from 1980-1989, which was the maximum

allowable volume for Prudhoe Bay into the Trans-Alaska Pipeline System. Prudhoe Bay

reservoir pressure is partially maintained through a water flood in the oil rim and gas

injection into the reservoir gas-cap. Even though field production was flat, the number of

wells gradually increased during this same time period and both gas and water

production increased. Individual wells exhibited declining production, offset by new wells

being drilled and completed.

The production data is graphed on a semi-logarithmic scale, even though it tends to

visually mask the severity of the decline rate, because this is a standard technique in

the E&P industry. After 1989, total field-wide production began to decline, falling from 1.5mmbopd to 0.6 mmbopd in 1998. This is a 10% per year depletion rate. However, during

the last nine years, over 575 new wells were brought on line which partially offset decline

rate. Graph 2 shows the production profile for all Prudhoe Bay wells drilled and

completed before 1989. The decline rate of only the wells drilled before 1989 nearly

doubles to 18% per year. During the same time frame, the average producing gas to oil

Water

Oil

Gas

10,000,000

1,000,000

100,000

10,000

1977 1980 1983 1986 1989 1992 1995 1998

10%/Year

bopdormcf/day

Source: PI/Dwi hts Simmons & Com an International


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ratio increased from 2,700 to 13,000 cubic feet of gas per barrel of oil, and the producing

water to oil ratio increased to almost 2:1 (two barrels of water produced for every barrel

of oil) from 0.5:1.

Graph 2: Prudhoe Bay Production From Wells Drilled Prior To 1989

The depletion rate at Prudhoe Bay, ranging from 10% per year to 18% per year, is

driven by the activity level. In addition to drilling new wells, the Prudhoe Bay Field

operators increased gas injection capacity from 4 billion cubic feet per day to 8 billion

cubic feet per day during the early 1990s. Since the produced gas is re-injected,

increasing the gas handling capacity allows for higher field-wide oil production rates,

partially offsetting depletion.

As Simmons & Company has delved deeply into the depletion issue, we created two

new oil & gas terms: gross depletion and net depletion. We define gross depletion as

the depletion rate with no drilling activity; in the Prudhoe Bay example, the gross

depletion is 18% annually. The net depletion is the depletion rate with on-going and

future drilling activity; in the Prudhoe Bay example the net depletion rate is 10%annually. It is important to note that the gross depletion case is not a do nothing case.

Workovers of existing wells and the implementation of secondary or tertiary recovery

techniques are captured in the production profiles, which tend to offset base production

decline. Thus, a true do nothing scenario at Prudhoe Bay (just basic maintenance)

would have a production decline significantly higher than 18% annually.

Oil

Water

Gas

10,000,000

1,000,000

100,000

10,000

1977 1980 1983 1986 1989 1992 1995 1998

18%/Year

Source: PI/Dwights, Simmons & Company International

bopdormcf/


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Several factors influence the levels of net and gross depletion rates. They include the

maturity of the field or basin, including reservoir rock and fluid properties, availability of

existing infrastructure, recovery mechanism, and the aggressiveness of the development

program (which is a function of oil price).

Preliminary analysis of many other basins that we are currently studying shows

that gross depletion rates in the range of 15% to 20% per year are typical!

THE DIFFERENCE BETWEEN GROSS & NET DEPLETION IS A LOT OF DRILLING

It should be clear from the Prudhoe Bay example that the difference between gross and

net depletion is a lot of added drilling and work-over activity. In order to accurately

forecast oil supply, at least from all non-OPEC sources, the base or gross level of

depletion must be known and the planned level of added drilling activity level accurately

anticipated.

For many OPEC producers, depletion is also becoming a very significant supply issue.

Senior oil executives at Venezuelas PDVSA have estimated that PDVSA needed to

increase their 1997 oil production by 1.2 million barrels per day to effect a net increase

of 350,000 barrels per day as their gross depletion rate using up the additional 850,000

barrels per day. OPEC producers like Saudi Arabia and Kuwait still have the luxury of

enjoying flat production from some of their large fields, though recent reports from both

countries indicate that both Ghawar and Burgin, the worlds two largest oil fields are now

beginning to encounter serious water problems and are starting to experience field-wide

production decline.

The following graph shows the trend of quarterly non-OPEC supply and international rigcount since 1993. Even though the rig count was high in the first half of 1998, the

production volumes started to flatten out even though all the rigs in the world were

working!


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Trends of non-OPEC Crude Oil Supply and International Rig Utilization

37

39

41

43

45

47

1Q93

2Q93

3Q93

4Q93

1Q94

2Q94

3Q94

4Q94

1Q95

2Q95

3Q95

4Q95

1Q96

2Q96

3Q96

4Q96

1Q97

2Q97

3Q97

4Q97

1Q98

2Q98

3Q98

4Q98

OilProd

uction,mmbopd

600

650

700

750

800

850

#OfActive

Rigs

Non-OPEC Oil Supply

International Rig Count

Source: IEA, Baker Hughes, Simmons & Company International

WHAT HAPPENS TO DEPLETION WHEN OIL PRICES COLLAPSE

The recent collapse in the price of oil has started to cause severe reductions in capital

budgets by majors, independents and national oil companies. The rig count has

decreased significantly in the fourth quarter 1998 and we expect this trend to continue

into first quarter 1999. The result of drilling fewer wells will be less new wells completed

and produced. This will almost certainly cause the incremental new production volumes

in 1999 to be less than the underlying production declines; at least in many of the non-

OPEC areas of supply. This reduced drilling activity will result in a decrease in non-

OPEC production in 1999. The severity of this decline will be a function of what

projects are dropped as budgets are cut and the current decline rates in each producing


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area. To the extent the cuts are primarily limited to exploratory drilling, it moderates the

impact on 1999 supply. But, it then has a profound impact on production rates in 2000

and beyond. If budget cuts force operators to slow development activities or bring them

to a halt in some fields, then production declines move toward the gross depletion rates

of 15 to 20% or higher in some areas.

THE IMPACT WHICH TECHNOLOGY HAS ON DEPLETION

Some counter or even dismiss the depletion argument by saying that technology has

made it easier add new production volume. While we agree that incredible technology

advances in the upstream sector of the E&P business have been made over the last

decade, adding new production volumes is not easier. A recent study by Simmons &

Company of depletion trends in the U.S. Gulf of Mexico (GOM) showed that decline

rates were increasing for recently drilled oil and gas wells as shown in the following

figures.

Decline Rate Trends In Louisiana GOM Shelf

Source: PI/Dwights, Simmons & Company International I


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In fact, 80% of the gas production form the GOM shelf (less than 250 meters water

depth) is from wells drilled after 1991! Thus, drilling new news is a critical component of

maintaining production volumes.

It should be no surprise that exploration and development opportunities diminish over

time in a mature basin. We believe that the broad application of 3-D seismic and

horizontal drilling technologies in the early 1990s may have actually accelerated the

decline rates. 3-D seismic allowed the geologists and geophysicists to see smallerstructures that were previously not readily visible on conventional 2-D seismic.

Horizontal drilling technology allowed many of these smaller reservoirs to be developed

from existing platforms with fewer wells, creating an illusion that technology was making

it easier to exploit oil and gas on the GOM shelf. However, once the low hanging fruit

had been picked, the 3-D seismic technology was driving exploitation of smaller

(marginal) reservoirs.

The following graph showing the reserve distribution illustrates that smaller reservoirsare found as a basin matures. The graph shows reserve distributions for three separate

water depth increments in the GOM shelf (less than 100, and 100 to 300, and between

300 and 1000).

0%

10%

20%

30%

40%

50%

1970

-71

1972

-73

1974

-75

1976

-77

1978

-79

1980

-81

1982

-83

1984

-85

1986

-87

1988

-89

1990

-91

1992

-93

1994

-95

1996

Wells Completed During Time Period

EffectiveDeclineRate,

%/yr


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The data show that the reserves are found early in the life of a basin. In the GOM, we

treat different shelf water depths as different basins as technology allowed deeper

exploration and development. The first commercial discovery in the Offshore GOM (up to

100) was in 1947 and 50% of the reserves were discovered in the first 10 years. The

first commercial discovery for water depths between 100 and 300 occurred in 1956 and

50% of the reserves had been discovered in the first 14 years. Finally, the first

commercial discovery in water depths between 300 and 1000 occurred in 1965 and

50% of the reserves were discovered in the first nine years.

GOM Shelf Reserve Distribution as a Function of Discovery Date

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Fields, Cumulative Frequency, by Date

CumulativeFrequencyReserv

es

up to 100' water

depth

100' to 300'

water depth

300' to 1000'

water depth

Source : Minerals Management Service, Simmons & Company International


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On the GOM shelf, technology has allowed the commercial exploration and development

of smaller reservoirs!

DEPLETION IS A SERIOUS SUPPLY ISSUE

The industry has clearly not taken the issue of depletion seriously. Some have tended to

scoff even at the mere concept, let alone its impact, as being synonymous with the world

running out of oil. Nevertheless, it is a serious supply issue. It is now impossible to

predict with any degree of reliability what the future rates of oil and gas production are

likely to be without first understanding field by field depletion rates. The International

Energy Agency (IEA), for instance, has already missed its fourth quarter 1998 estimated

rate of non-OPEC supply by 4.1 million barrels per day. This must be the largest revision

to their published forecasts in their 25-year history. While their analysts tend to dismiss

these supply revisions as one-time events, they are most likely driven by depletion rates

in too many parts of the world now equaling to exceeding the rate of any supply addition.

To put the issue in its most staggering context, the world now produces approximately

110 million barrels per day of oil and gas (BOE.) If the gross rate of depletion is a mere

10% per annum over the next 11 years, then 83 million barrels per day of added

wellhead oil and gas production is needed to merely cope with flat demand. If demand

for oil and gas grew by only 1% per annum over this same period of time, then the new

supply additions need to total another 12 million barrels per day.

Whether such rates of expansion are even physically possible given the limitations on

rigs and manpower, particularly after the 1998 oil price collapse, is a serious long-term

energy issue that needs at least an intelligent debate.

At the least, the oil and gas industry must pay attention to depletion rates. The industry

badly needs to begin developing supply studies, which clearly incorporate intelligent

estimates of depletion. Otherwise, all future supply estimates will likely be overstated.

Perhaps the IEAs supply miss of 1998 is merely a harbinger of all future supply

forecasts because depletion was badly ignored.

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