Depletion: The forgotten factor in supply and demand

Some areas now hitting 15-20%

Matthew R. Simmons, David A. Pursell
Simmons & Company, International

Prudhoe Bay production from wells drilled prior to 1989 [10,096 bytes]
Trends of non-OPEC crude oil supply and international rig utilization [19,029 bytes]
Decline rate trends in Louisiana GOM shelf [18,981 bytes]
GOM shelf reserve distribution as a function of discovery date [13,555 bytes]

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.

All hydrocarbon reservoirs ultimately begin a production decline. Yet, no one produces reliable field-by-field decline estimates, let alone even makes a guess at the current blended rate for the worldwide production base of oil and gas.

The issue was not particularly serious for years, when a high percent of the world's oil and gas production was coming from giant fields years away from any decline. And, when the world had tens of million bbl 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 3-4 million b/d, 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 world's 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. The rapid use of all the new forms of oil field technology tends to increase the decline rate of many fields, once peak production has been achieved.

What is depletion?

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 production to decline. The production rate will eventually decline below an economic limit. Then, 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.

Depletion's history

In the early 1900's, the goal for many companies was to produce the oil out of the ground as quickly as possible - known as "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 production rates were extremely high and declined very rapidly in this mode. For example, at the height of the development of the East Texas Field in the early 1930's, there were 12 wells drilled on 1/5 of an acre in Kilgore, Texas.

Eventually, regulatory authorities limited the number of wells drilled to fewer than 16 per square mile (or 1 well/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 partially or completely offset the decline from the older wells. The Prudhoe Bay Field on Alaska's North Slope illustrates this situation.

Classic depletion

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 field. Third, Prudhoe Bay's operators have applied "best in class" reservoir management practices.

Oil production was constant at 1.5 million b/d of oil 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.

After 1989, total field-wide production began to decline, falling from 1.5 million b/d to 0.6 million b/d in 1998. This is a 10% per year depletion rate.

During the last nine years, over 575 new wells were brought on line, which partially offset the decline rate. 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-oil ratio (GOR) increased to 13,000:1, from 2,700:1, and the producing water-oil ratio (WOR) increased to almost 2:1, from 0.5:1.

The depletion rate at Prudhoe Bay ranges from 10% per year up to 18% per year, and is driven by the activity level. In addition to drilling new wells, the operators increased gas injection capacity from 4 bcf/d to 8 bcf/d 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.

Gross and net depletion

Simmons & Company has created two new oil and 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.

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

Maturity of the field or basin, including reservoir rock and fluid properties
Availability of existing infrastructure
Recovery mechanism
Aggressiveness of the development program

Preliminary analysis of many other basins that we are currently studying shows that gross depletion rates in the range of 15-20% per year are typical.

Drilling's effect

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. To accurately forecast oil supply, at least from 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 Venezuela's PDVSA have estimated that PDVSA needed to increase their 1997 oil production by 1.2 million b/d to effect a net increase of 350,000 b/d as their gross depletion rate "used up" the additional 850,000 b/d.

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 world's two largest oil fields are now beginning to encounter serious water problems and are starting to experience field-wide production decline.

The trend of quarterly non-OPEC supply and international rig count since 1993 shows 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.

Oil price effects

The recent collapse in the price of oil is causing severe reductions in capital budgets by majors, independents and national oil companies. The rig count 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 fewer new wells completed and produced. This will likely cause the incremental new production volumes in 1999 to be less than the underlying production declines, at least in many non-OPEC supply areas. 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 the projects cut from budgets, and the decline rates in each producing area. To the extent the cuts are 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 or halt development activities, then production declines move toward the "gross" depletion rates of 15-20% or higher in some areas.

Technology impact

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 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 US Gulf of Mexico (GOM) showed that decline rates were increasing for recently drilled oil and gas wells. In fact, 80% of the gas production from the GOM shelf (less than 250 meters water depth) is from wells drilled after 1991. Thus, drilling new wells is a critical component of maintaining production volumes.

Diminishing returns

It should be no surprise that exploration and development opportunities diminish over time in a mature basin. We believe that the broad application of 3D seismic and horizontal drilling technologies in the early 1990s may have actually accelerated the decline rates.

Three-dimensional seismic allowed the geologists and geophysicists to "see" smaller structures that were previously not readily visible on conventional 2D 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. The 3D seismic technology was driving exploitation of smaller (marginal) reservoirs.

The data shows 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 ft) was in 1947 and 50% of the reserves were discovered in the first 10 years. The first commercial discovery for water depths between 100 ft and 300 ft 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 ft and 1,000 ft occurred in 1965 and 50% of the reserves were discovered in the first nine years. On the GOM shelf, technology has allowed the commercial exploration and development of smaller reservoirs.

Serious supply issue

The industry has clearly not taken the issue of depletion seriously. Some skeptics 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 b/d. 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 heavily influenced by depletion rates in too many parts of the world that are now equaling or exceeding the rate of any supply addition.

To put the depletion issue in its most staggering context, the world now produces approximately 110 million boe. If the gross rate of depletion is a mere 10% per annum over the next 11 years, then 83 million b/d 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 b/d.

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 IEA's "supply miss" of 1998 is merely a harbinger of all future supply forecasts because depletion was badly ignored.