RJD revitalizes mature Kansas oilfield

Oct. 6, 2014
The benefits of horizontal drilling are not limited to previously undeveloped fields or by lithography.

Ahmed H. Kamel
University of Texas Permian Basin
Odessa

The benefits of horizontal drilling are not limited to previously undeveloped fields or by lithography. Mature fields whose production has declined over time can be reinvigorated as well, creating new opportunities if drilling and completion technology is matched to economies of scale.

In 40-year-old Donelson West field, which covers about 1,200 acres in Cowley County, Kan, radial jet drilling (RJD) was used effectively to recomplete several mature wells.

This article presents an overview of RJD procedures and technologies in horizontal wells, reviews the production history of Donelson West field, summarizes the workover effort, and compares data from before and after the recompletion.

Employed in existing oil and gas wells at depths of 4,500 ft and shallower, RJD is a cost-effective application to complete vertical and horizontal wells. It has been proven to enhance production rates, reduce decline rates, reduce near wellbore damage, and recover more resources from stripper wells.

It is also an alternative to traditional perforation and extended-horizontal-penetration beyond the near-wellbore damaged zone, acid wash and matrix acidizing, and traditional water injection and disposal applications.

RJD is ideal for small-diameter horizontal completions, which we will review in this article. As opposed to a conventional bit and drilling mud, RJD expels water, diesel, or acid through a high-pressure hose and a nozzle to drill into the formation.

The nozzle has orifices that face forward cutting the rock and backward at a 45° angle pushing the nozzle into the formation and widening the hole behind the nozzle (Fig. 1).

RJD procedure

The first step in RJD is to remove production equipment from the well and rig up the coiled tubing unit (CTU) to deliver the hose down the well. The end of the CT is equipped with a 90° deflector shoe that points sideways into the formation when lowered downhole.

CT is then lowered into the well until the deflector shoe reaches the target formation. In a cased-hole application, a special cutter is lowered into the well by CTU until the cutter reaches the casing.

The cutter is then energized to perforate the casing and cement. After penetration, the high-pressure, jet-nozzled hose is lowered downhole via the CT.

Once the nozzle has reached the formation, the drilling fluid is pumped through the high-pressure hose and nozzle, which both jets the lateral and advances the nozzle and hose into the formation. The jet of fluid exits the nozzle at very high speeds, erodes the reservoir, and drills the lateral.

Finally, the pressure in the hose is decreased as the hose is removed, circulating out any remaining cuttings. The process is repeated as many times as necessary, depending on the number of laterals.

RJD procedures vary depending on the operators and their proprietary equipment. Some mill the casing and then jet the hole. Others mill the casing, turn the deflector shoe, mill another hole in the casing, and then jet the holes into the formation.

Still others use abrasive sand in the jetting fluid to cut through the casing instead of a cutter. These are slight variations, however, and each still follows the basic procedure of milling the casing and jetting the hole.

RJD equipment

RJD requires specialized equipment. The casing cutter is typically a burr mill run by a mud motor. The jetting nozzle has several orifices that face forward and several that face backward at a 45° angle. The overall nozzle diameter varies from 0.5-0.75 in. and is about 1 in. long. Fig. 3 illustrates the nozzle and lateral as the forward spray cuts the formation and the backward spray accelerates the nozzle into the rock, circulating cuttings from the hole. Fig. 4 shows several RJD holes in sandstone.

The jet nozzle cuts forward and pushes backward. (Fig. 3)

There are three primary penetration mechanisms that drill the rock: erosion, pore-elastic tension, and cavitation. The high-pressure fluid jet erodes the formation by pumping a small amount of water at high pressure and high velocity through a very small hole. Pore-elastic tension occurs when high-pressure water enters the pore space, increasing the pore pressure and causing the rock to fracture.

These patterns are typical of RJD in sandstone. (Fig. 4)

The sudden increase in pore pressure produces cavitation. Fluid-free bubbles are formed in the areas of lesser pressure and immediately implode, causing shockwaves that enhance the fracturing of the formation.

In RJD, the CTU resists the weight of the hose hanging in the well as well as the force created from the backward-facing jets in the nozzle. As a result, the high-pressure hose is subjected to high tension, which pulls tight the high-pressure hose and ensures a straight bore (Fig. 5).

Drilling fluids

The fluid pumped through the high-pressure hose to the nozzle varies, depending on reservoir lithology and formation fluid properties. In most cases, water is sufficient as it has obvious advantages: It is cost effective, readily available, easily disposable, and comes with no health, safety, and environmental (HSE) issues.

In water-sensitive formations, however, diesel fuel may be used to drill the radials. Diesel fuel also has solvent properties that may be advantageous for waxy reservoir fluids. It aids penetration by cutting paraffin in the formation and does not emulsify as water might. In carbonate formations, hydrochloric acid is an advantageous drilling fluid, combining the effects of pressure and dissolution of carbonates.

Abrasiveness is achieved by adding proprietary sand to the fluid, physically eroding the casing and formation. The use of abrasives can eliminate the need for a separate cutter to penetrate the casing.

Advantages, limits

The primary benefit of RJD is that it is economical. It is a cost-effective method to complete vertical wells to perform as an openhole horizontal completion performs.

Drilling a new or sidetrack horizontal completion with a rotary rig requires pulling the tubing, killing the well, and drilling large-diameter completions at traditional rates of penetration. These expenses can make drilling horizontal wells with a rotary rig cost prohibitive in a small field.

RJD can be accomplished with a small CTU and standing pumping equipment. With the appropriate combination of deflector shoe and tubing diameter, the laterals can be jetted through-tubing. This eliminates the need to pull production tubing.

RJD is also fast. Utilizing existing well shafts, RJD technology can laterally enter areas in a wheel-and-spoke fashion, penetrating up to 300 ft in up to 16 directions at any given depth. With it, eight laterals can be drilled in only 2 days, as opposed to a typical period of 4 weeks/well.

In additional, RJD does not use traditional drilling mud. There is no formation damage from filter cake build up on the rock face.

It allows multi-layer application in thicker reservoir zones, reduces the need for additional stimulation, and avoids the problems associated with changes in well-bore configuration.

RJD does have limitations. The most significant is that while a jet-drilled lateral begins to mimic the performance of a horizontal completion, it is not a horizontal completion. There is no way to complete the lateral with a liner because it is impossible to run casing into the lateral.

Managing future production from a well could be difficult, and an operator may not be able to shut off flow from the lateral. Reentering the lateral after it has been drilled can be very tricky, and pumping some type of squeeze down it can be problematic.

There also are no surveillance options inside the lateral. If the lateral begins to produce water or gas, there is no way to diagnose which part is contributing to the flow since standard logging tools likely won't fit into the lateral.

Directional control of the lateral makes reaching specific targets difficult and presents the risk that the lateral could extend out of the target zone and into a zone that contains either water or gas.

Additionally, laterals can prematurely terminate due to fractures, faults, or other reservoir heterogeneities. With no way to steer the nozzle while it is drilling, if it runs into one of these barriers, it can turn path or lose flow.

RJD in declining field

Despite these limitations, RJD has been deployed in mature fields over the last several years. Kansas's Donelson West field is one success story among many.

The field's target formation is the Altamont limestone, in the upper part of the Marmaton group in the Middle Pennsylvanian series. It is a fine crystalline limestone that varies in color from light brown to brownish white.

The formation displays some pinpoint and vugular porosity, which varies 15-20%. Permeability varies from 1 to 10 md and net pay thickness varies from 6 to 10 ft. The combination of low permeability, low productivity from traditional vertical completions in a thin net pay, and lack of low-cost techniques to improve well productivity caused the production to dwindle.

The formation volume factor of produced crude is 1.1. Reservoir volumetrics indicate that a total of 2.7 million bbl were originally in place. With a 35% recovery factor, as much as 0.95 million bbl may be recoverable.

Donelson West began production in 1967 and was producing 83,000 bbl from 13 wells by 1968. However, production quickly began to decline.

Over the last 10 years, production from the field has been very low. During 2000-09, the field averaged only 1,033 bbl/year, with a maximum production of 1,701 bbl/year in 2009 (Fig. 6). Despite the low production compared with the early years of the field, there has been an upward trend overall as well as an increase in the number of wells online (Fig. 7).

During 2001-02, there was a decrease in production, and the number of producing wells went to four from five. As wells came back online in 2003, production increased.

During 2003-04, the well count decreased by two, but by 2005, it was up to 10. Oil production during 2004-07 steadily decreased, however, which may be related at least partially to the low well counts in 2006 and 2007.

After 2007, production steadily increased from less than 1,000 bbl/year to nearly 2,500 bbl/year. During this time, oil prices were steadily increasing. It is likely that much of the up and down in the well count and modest growth in production was due to the oil price increase and attempts to boost production by optimizing the surface kit.

Despite the low production over the last 10 years, the lease has significant potential. Cumulative production from the field through 2011 was about 0.45 million bbl. With an original oil in place of 2.7 million bbl, only about 17% of total reserves have been produced, and 2.2 million bbl remain.

Because there has been no pressure support, it is possible that the field's total recovery factor could be improved significantly. If total recovery is increased to 35%, as much as 0.5 million bbl of additional reserves could be recovered.

Given the low production, long history, and sizeable remaining reserves, this lease may was a candidate for investment.

Donelson West redevelopment

Donelson West field was originally developed with vertical completions. These were followed by acid and nitrogen fracturing. The wells were not all identically treated, and those treated with 10,000-15,000 gal of acid and 125 MMcf of nitrogen produced at higher rates than other wells fractured with less acid.

Team Resources Inc. acquired a 320-acre lease in the field in late 2010 and soon began developing a program to produce the remaining recoverable reserves. The company planned to stimulate the existing wells and initiate an infill drilling program.

The initial phase consisted of recompleting and stimulating eight existing wells and drilling two new wells in the lease. The field was drilled on 10-acre spacing, and each well was completed with RJD laterals. After the laterals were completed, each was hydraulically fractured with 15,000 gal of acid and 250 MMcf of nitrogen.

The laterals were drilled over several weeks. Two of the wells were jetted on the same day. Each of the remaining wells took a full day to jet.

The old wells were completed with four different 600-ft laterals with each requiring 500 gal of acid to drill. The new wells were also completed with four different 600-ft laterals but with 400 gal of acid for each lateral, instead.

After the jetting, each well was stimulated with a 15,000-gal acid frac followed by 250 MMcf of nitrogen and then put on production.

Both of the new wells came on strong with flush production, and seven of the existing wells came on as well. One of the existing wells, in the western portion of the field never came back online. The formation generally thins to the west, and the combination of thin pay and low pressure is probably to blame.

Despite this small setback, there was a definite uptick in overall production. Table 1 summarizes total monthly field production before and after the workovers.

During 2006-07, the field was producing from only five wells. During 2008-10 all 10 of the wells produced.

As Table 1 indicates, before the workovers, the field was averaging about 157 bbl/month over the last 3 years. After the workovers, the field averaged 938 bbl/month, a six-fold production increase (Fig. 8).

While the production numbers after the workover include two new wells, there is adequate production information to separate production from the new wells from the production from the old wells (Fig. 9).

Generally speaking, the two new wells accounted for 70-80% of total lease production. These wells came on strong and, as the adjacent pressure depleted, their production declined. The remaining 20-30% of current lease production has been consistently better than 200 b/d.

There was abnormally high production in March 2012. Just before this, the pumps on the two old wells were replaced. The pump replacement resulted in short-term production benefits that are primarily responsible for the production increase.

In June 2012, production from both the old and new wells was down slightly. During this time, there were production disruptions associated with additional infill drilling and bringing those new wells online (Fig. 10).

The increase in production after the RJD and acid fracturing is evident. Before RJD, the wells struggled to reach 200 bbl/month. Afterwards, production reached nearly 500 bbl for 1 month and is consistently in the range of 250 bbl/month.

Table 2 presents monthly production data for all the old wells before and after the workovers, while Table 3 summarizes average monthly production per well and Fig. 11 is a plot of these data.

During 2008-10, the field averaged 157 bbl/month from the old wells. For the 9 months after RJD and acid fracturing, the wells have averaged 264 bbl/month. Much of the variation in historical production, however, is due to fluctuating well count. During periods when wells were shut in, production was down.

After normalization for well count, the success of the treatment is evident. The per-well average production rates for the 3 years before RJD was 16 bbl/month. After the treatments, it is about 38 bbl/month.

Even excluding the 7 months in which production benefits from two pump replacements were seen, the average rate per well is 34 bbl/month. This is a two-fold increase in production. Can the success be solely from RJD?

Contributing success factors

This reservoir has suffered from major pressure depletion. Initial production declines were very severe and began immediately. There has never been any pressure support.

As a result, the field is producing at very low drawdown with beam bumps. Much of the pumping equipment was repaired or replaced during the period when the RJD and acid fracturing were being completed.

In addition, there is no production data available between the completion of the jet-drilled laterals and the acid fracturing.

The overall production increase from the old wells is likely due to at least some interaction between the new pumping equipment and the RJD and acid fracturing. Some of the production increase is likely due to higher drawdown (as witnessed in the seventh month of production when two pumps were replaced).

Furthermore, some of the productivity increase is due to the laterals, and some is due to the acid fracturing. Unfortunately there is no way to separate the benefits of these due to scarcity of data.

Finally, metering at the field is very basic. Oil production is based on production over relatively long periods and sophisticated flow measurements and data simply don't exist.

Historical production is based on Kansas Geologic Society databases. The data are available only on an annual basis, and well counts in particular may mask actual field performance.

Mechanisms of productivity increases

The observable success of the RJD and acid treatments is the pronounced increase in oil rates. The real question, however, is under what mechanism does RJD affect well productivity.

There are several possible scenarios. The first is simply that the laterals expose more rock face and increases the amount of rock that can flow.

It is also possible that the laterals change the flow regimes from radial flow to something that behaves more like a horizontal completion with more linear flow.

In this particular case of vugular limestone, it may be that the laterals have opened up some of the vugularity or other diagenitic features in the formation that are contributing to the flow.

The use of acid as a jetting fluid and subsequent acid fracturing may be a contributing factor, as well. It is probable that the long horizontals, though small diameter, are able to aid fracture propagation.

Four laterals/well, each penetrating 600 ft into the formation, could be a significant head start for fracture propagation. Conversely, they could also hinder fracture propagation if the laterals themselves contribute to leak off and the fluid can't sufficiently breakdown the formation.

The effect of acid in limestone is understood to be of a major benefit. It is also possible that the orientation of the laterals is important.

Whereas hydraulic fracturing tends to propagate fractures parallel to the formation's natural fractures, RJD enters the rock perpendicular to the natural fractures and opens up flow through them.

The particular mechanism that caused the productivity increase at this field is uncertain, but it is probable that it is a combination of these factors.

Acknowledment

The author thanks Steven D. Cinelli for his co-authorship of the paper from which this article derives.

Bibliography

Abdel-Ghany, M. A., Siso, M., Hassan, A. M., Pierpaolo, P., and Roberto, C., "New Technology Application, Radial Jet Drilling Petrobel, First Well in Egypt," 10th Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, Mar. 23-25, 2011.

Bruni, M., Biassotti, H., and Salomone, G., "Radial Drilling in Argentina," presented to the SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, Apr. 15-18, 2007.

Buckman Jet Drilling: Leading Innovators in Jet Drilling Technology, www.buckmanenergyservices.com, 2010 (accessed Apr. 14, 2012).

Dickinson, W., and Dickinson, R., "Horizontal Radial Drilling System," SPE California Regional Meeting, Bakersfield, Mar. 27-29, 1985.

Dickinson, W., Dickinson, R., Herrera, A., Dykstra, H., and Nees, J., "Slim Hole Multiple Radials Drilled with Coiled Tubing," Second Latin American Petroleum Engineering Conference, II LAPEC, Caracas, Mar. 8-11, 2002.

Dickinson, W., Dykstra, H., Nordlund, R., and Dickinson, R., "Coiled-Tubing Radials Placed by Water-Jet Drilling: Field Results, Theory, and Practice," 68th SPE/ATCE, Houston, Oct. 3-6, 2003.

Dickinson, W., Pesavento, M., and Dickinson, R., "Data Acquisition, Analysis, and Control while Drilling with Horizontal Water Jet Drilling Systems," International Technical Meeting, Calgary, June 10-13, 1990.

Gidley, J.L., Holditch, S.A., Nierode, D.E., and Veatch, R.W., "Recent Advances in Hydraulic Fracturing. Monograph Series," Vol. 12, Richardson, Tex., SPE Textbook Series, 1999.

Kansas Geological Survey, Stratigraphic Succession in Kansas, 2005.

Kansas Geological Survey, Stratigraphy of the Marmaton Group in Kansas, 2010.

Marburn, B., Sinaga, S., Arliyando, A., and Putra, S., "Review of Ultra short-Radius Radial System (URRS)," International Petroleum Technology Conference, Bangkok, Feb. 7-9, 2012.

Towler, B.F., "Fundamental Principles of Reservoir Engineering," Vol. 8 (3-4), Richardson, Tex.: Textbook Series, SPE, 2002.

Yonghe, L., Chunjie, W., Lianhai, S., and Weiyi, G., "Application and Development of Drilling and Completion of the Ultra short-radius Radial Well by High Pressure Jet Flow Techniques," SPE International Oil and Gas Conference and Exhibition in China, Beijing, Nov. 7-10, 2000.

The author

Ahmed H. Kamel ([email protected]) is associate professor of petroleum engineering at the University of Texas Permian Basin, Odessa. He holds a BS and MS in petroleum engineering from Al-Azhar University, Cairo, and a PhD from the University of Oklahoma, Norman, also in petroleum engineering. He is an active member in the Society of Petroleum Engineering, the American Association of Drilling Engineers, and the Society of Rheology.

Correction

In "Virtual flow metering improves Chinese offshore production" (OGJ, Sept. 1, 2014, p. 92) by Zhi Wang, Jing Gong, Haihao Wu, Changcun Wu, and Qingpin Li, the abbreviation VMS was incorrectly used in place of VFM for oil and water volume comparisons in Figs. 7 and 8.