DOWNHOLE INJECTION OF OBM CUTTINGS ECONOMICAL IN NORTH SEA

R.C. Minton
BP Norge UA
Stavanger

N. Last
BP Group Research & Engineering
Sunbury-on-Thames,
Middlesex, U.K.

Annular injection offers an economical disposal mechanism for the oily cuttings and associated wastes generated from the use of oil-based muds in drilling operations.

This disposal mechanism eliminates overboard cuttings discharges and, hence, removes much concern regarding the environmental impact of these wastes. Continued use of oil-based muds, which perform better than many water-based muds, is therefore feasible.

Thus, BP Norway UA has been using the cuttings slurrying and injection process as the prime disposal mechanism for drilling wastes on the Gyda platform in the North Sea since July 1991.

Low-toxicity, oil-based muds are widely used in the North Sea and have significant operational benefits. The greatest gains are in development drilling, but the process is equally applicable in exploration and appraisal drilling.1 2 The overboard discharge of the oil-contaminated cuttings leads to environmental damage that, although localized, is still unacceptable.3

BP evaluated novel water-based muds that eliminate this problem.4 Additionally, a range of cleaning and disposal options for the oily cuttings has been reviewed.5

Of these options, cuttings slurrying and injection appeared to offer the most economic,il solution, particularly because this method would also tackle the problem of disposing oily liquids from the drilling unit.

This method was an established practice in Alaska and the Gulf of Mexico, but the technique had not been previously used in the North Sea.6 7

Following discussions with Norwegian authorities, BP Norway obtained permission to try the process on the Gyda platform in 1991.

This trial proved successful and led to the adoption of the technique as a routine disposal mechanism.8 Since the trial in July 1991, more than 250,000 bbl of oily waste have been injected into the subsurface formations without major incident.

This disposal method has eliminated the discharge of about 6-50 metric tons of rock and more than 50 metric tons of associated oil from each well-some 8,000 metric tons of rock and 650 metric tons of oil overall.

COMPLIANCE OPTIONS

Given the requirement to discontinue the discharge of oily cuttings, BP Norway was faced with a range of compliance options. Two options were the use of water-based muds or the use of the recently developed oil-based muds with ester or ether chemistry. In each case, the cuttings could be discharged, removing the need for further processing. Alternatively, low-toxicity, oil-based muds could still be used, with the cuttings transported to shore for processing or converted into a slurry and then injected.

Because water-based muds had been used on some of the earlier appraisal wells in the area, a comparison of drilling performances i could be obtained. Similarly, BP Norway had field tested a biodegradable oil-based fluid and could compare its cost to the cost of the other options. LoiN,-toxicity, oil-based mud performance data were available, and the cost of onshore disposal and the likely cost of slurrying and injection could be established. The resultant analysis demonstrated that, for a 20-well program, cuttings injection would cost some $9.6 million (about LL6.4 million) compared to 518, $19.5, and $39 million for the onshore processing, biodegradable oil-based mud, and water-based mud options, respectively (Fig. 1).

Similar drilling performances could be assumed for the two oil-based muds, but experience had shown that water-based mud was a less efficient fluid (Fig. 2). The better performance of oil-based muds had implications for the timing of the Gyda wells and, hence, the cash flow. The quicker drilling times with the oil-based mud, in turn, had a significant impact on the net present value of the field and discounted further consideration of the water-based mud option.

This analysis was the basis for BP's initial approach to the Norwegian authorities to approve the injection test.

INJECTION PROCESS

The Gyda field has a Jurassic reservoir at a depth of about 4,000 m, situated in Block 2/1 of the Norwegian sector of the North Sea. This reservoir is overlain by mud-stones, chalk, and the massive Tertiary mudstones of the Hordaland/Nordland groups. The reservoir is typically drilled with a 6-in. hole.

A 7-in. liner is usually set immediately above the reservoir. The 9 5/8-in. casing is set at 3,200 m, the 13 3/8-in. casing at 1,030 in, and the 27-in. conductor at 310 m.

The 12 1/4-in., 8 1/2-in., and 6-in. holes are drilled with low-toxicity, oil-based mud. The cuttings and oily drain water generated in these sections are disposed of through injection.

Fig. 3 is a schematic diagram of the slurrying and injection process. The oily cuttings are separated from the circulating fluid conventionally using the solids control equipment. The cuttings then pass into the primary slurry tank where they are mixed with sea water. A centrifugal pump fitted with a tungsten carbide-impregnated impeller then circulates the slurry for the initial break up of the cuttings. The resultant slurry then passes to the second tank where continued circulation ensures that the cuttings are finely dispersed.

Most of the time this results in slurry properties that are suitable for pumping (Table 1). On some occasions, however, additional viscosity is required, primarily during the drilling of the chalk and sandstone intervals.

The finished slurry then passes to a holding tank until a sufficiently large batch is ready for injection. One of the mud pumps, or the cement unit, then injects the slurry into the previously drilled well. The fluid is pumped down the 9 5/8 in. x 13 3/8 in. annulus and out into the formation at the 13 3/8-in. shoe at about 1,030 m true vertical depth (TVD).

The slurry particle size distribution is typified by a D90 of 120 m, a D50 of 9 m, and a D10 of 2 m. Some larger particles can be present, particularly during drilling of the chalk section where chert may be encountered. These larger particles are removed by a coarse mesh strainer in the line prior to the high-pressure injection pump.

INJECTION HISTORY

Since the slurry injection disposal process began in July 1991, there have been no oil-contaminated discharges from the drilling unit.

Twelve wells have been drilled in this period, and the thirteenth is in progress. Fig. 4 is a summary of the injected volumes, and Table 2 details the volumes plus the injection rates and pressures.

A total of 162,000 bbl of slum and 102,000 bbl of oily water have been injected into the 12 annuluses, with injection ongoing into the annulus of well A18. The volumes pumped into each annulus vary, but for the last six wells the volume has been controlled to about 25,000 bbl. This volume is half that required to fracture up to the shallower sands above the 13 3/8-in. shoe.

Injection of each individual batch of slurry commences slowly, at 0.5-1 bbl/min, to initiate or reopen the fracture. The injection rate is then increased to 8-10 bbl/min, controlled as a function of the injection pressure and the slurry density.

A maximum of 2,000 psi is permitted if the annulus is full of oily water; the maximum is 1,500 psi with 1.6 sp gr drilling fluid in the annulus. These pressure limits are a function of the injection depth, casing strengths, proven leak-off data, fluid densities, and the effect of wellhead lift off. The pressure limits must be determined separately for other injection scenarios. Usually, injection pressures are about 1,200-1,600 psi.

There are no specific actions defined at the end of the injection in any particular annulus. Because of the nature of the operation and the relative volumes of slurry and oily water, the annulus is normally full of oily water at final shut in. The shut in pressures on the annuluses are then monitored daily (Table 3).

The maximum pressures in these annuluses are controlled by bleeding off small volumes of fluid. Pressure is bled off if the annulus pressure exceeds 1,500 psi. Hence, the upper pressures are limited, and several of the data points reflect periods immediately, after bleed down rather than a pressure decay. In fact, with the exception of the annulus of Well A19, there is no evidence of leak off to the formation.

The pressure profiles are consistent with BP's assumptions that the fractures are confined to the Tertiary shale formation with no communication to the shallower sands.

In the case of A19, the pressure regime changed after 11,000 bbl had been injected. It seems probable that a minor sand lens had been intersected, allowing for the observed leak off.

FRACTURE PREDICTIONS

The principal environmental concerns with the injection process relate to the containment and long-term fate of the oily wastes. In addition, it is necessary to consider the possibility of fracture/well interference for existing and for future well bores, A series of simulations using 3D numerical fracture simulator Terrafrac quantified these parameters.9

For the Gyda injection program, these simulations show that about 52,000 bbl of slurry could be pumped at the 13 3/8-in. shoe depth of 1,030 m before the slurry would reach the unconsolidated sands at 500 m. In the absence of these sands, fracture to seabed would require pumping 90,000 bbl.10

Fig. 5 plots the predicted fracture height above the shoe against injection volume. Given the normal injection volume of around 25,000 bbl/well, it is clear that a large safety margin is available.

Breakout analysis from early wells in the Gyda field suggest that the maximum horizontal stress is in the northwest/southeast plane. It is reasonable to assume that the fracture plane will follow this same trend. Consequently, the potential for fracture;well interference can be established by comparing the maximum lateral projection of the fractures at the depth of interest.

Fig. 6 shows the analysis with the well locations plotted relative to one another at a depth of 1,030 m TVD (the 13 3/8-in. casing setting depth). This plot suggests that, with perhaps the exception of the A09 and A18 wells, the planes of the fractures are more than adequately separate from one another.

The fracture width is at most 1-2 in. Therefore, the probability of intersection in the horizontal plane is very low. Even in the A09 and A18 wells there is no indication from the pressure responses of fracture interference.

RESULTS

Experience from Gyda and other locations where BP has injected cuttings slurries shows that the technique is a simple, reliable, and economical means of disposing drilling wastes.
Sequential annular injection is a flexible disposal method.
Analysis of the hydraulic fracture propagation shows that at 25,000 bbl/well, there is a large safety factor to prevent unforeseen environmental pollution in the configuration adopted at Gyda.
Due consideration of the lateral extension of the fractures will ensure that subsequent well paths and drilling program are designed with little probability of fracture intersection.
The assumption of little or no leak off to the formation holds true. Bleed down of the annular pressures demonstrates that the slurry is relatively immobile. No attempt has yet been made to fully bleed: back the earlier used annuluses, however.
By implementing drill cuttings injection with the same technological standards routine to industry, oil-based muds can still be used with the risk of environmental pollution essentially eliminated.

ACKNOWLEDGMENT

The authors thank BP Norway for Permission to publish this article.

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