Study offshore Trinidad determines frac-pack effectiveness

B.M. Davidson
S.A. Holditch & Associates Inc.
College Station, Tex

D.A. Pursell
Simmons & Co. International
Houston

K. Owen
Texaco Inc.
Jakarta, Indonesia

P. Dukharan
Trinmar Ltd.
Trinidad

J. Maniere
Dowell Schlumberger
Caracas

A study determined that reservoir factors and not frac packing caused well performance in Trinidad's offshore Soldado field to be below expectations.

The field was discovered in 1950 (Fig. 1 [52,729 bytes]). Two years ago, the Soldado field operator, Trinmar Ltd., switched from gravel pack to frac-pack completions as the standard sand-control completion technique.

The switch attempted to improve completion efficiency while controlling sand production.

About 35 wells in the field have been frac packed, many with two or more separate frac-pack treatments.

The frac packs involved running a gravel-pack assembly (screens and packer) and creating a short, high-conductivity, propped hydraulic fracture. This was followed by a gravel pack.

Unfortunately, many of these wells did not meet production expectations. To determine whether the poor well performance was caused by the frac-pack completions or other causes, Trinmar (a joint venture between Texaco Inc. and Petrotrin Ltd.) initiated a study with the help of S.A. Holditch & Associates Inc. and Dowell Schlumberger.

The study determined that the frac-pack technique did create high-efficiency completions (low skin factor), and reservoir factors were responsible for the well performance being below expectations.

Treatment analysis

The study included Soldado hydraulic fracture treatment data in digital format along with information on treatment design and treatment summaries. Also used were production data and well histories for the frac-packed wells and pressure build-up analyses from 13 frac packed and 6 gravel-packed wells.

The analysis involved the following steps:

• Analyze fracture treatment data for five select wells with a 3D hydraulic fracture model to determine propped fracture length and conductivity.
• Review results from pressure build-up tests.
• Compare skin factors of frac pack and gravel-pack completions.
• Compare pressure results build-up tests with well performance.

The frac-pack treatments were performed to improve the completion efficiency while controlling formation sand production. The treatments successfully controlled sand; however, to determine if they resulted in high completion efficiencies, two steps were taken.

First, a 3D hydraulic fracture model was used to determine the fracture geometries. Specifically, propped fracture lengths and conductivities for several frac-packed wells were estimated with the Fracpro program.

Second, post-completion skin factors, from pressure build-up analysis, were compared for the frac packed and gravel-packed wells.

History matching the observed pressure response with a 3D fracture model is one of the best methods for determining fracture geometry. With a reasonable treating pressure match, the fracture model should closely predict the fracture geometry.

Both the mini-frac and fracture treatments for the five wells studied were evaluated with the 3D fracture model to obtain the fracture geometry.

This article describes the analysis on Well S711, but the same procedure was also applied to Wells S708, S688, S677, and S727.

Measured bottom hole treating pressures were available for all five fracture treatments analyzed.

Mini-fracs

Mini-frac treatments, small-volume injection tests at specified fracturing rates, were performed on all five wells. The treatments provided data for determining several parameters needed for hydraulic fracture design, such as:

• Fracture closure pressure (in situ stress)
• Fracture fluid leak-off coefficient (fluid efficiency)
• Near well bore friction pressure
• Injection rates and pressures at fracturing conditions
• Well bore mechanical integrity.

Because this analysis focused on evaluating fracture geometry, fracture closure pressure and fluid leak-off coefficient, C _t, were the main parameters obtained from the mini-frac data. Both parameters were determined from the pressure decline following the mini-frac treatment.

The net pressure (the bottom hole treating pressure minus the fracture closure pressure) is the pressure required to propagate a fracture. Fig. 2 [135,003 bytes]a shows the net pressure history match for Well S711.

Table 1 [46,811 bytes] summarizes all five mini-frac treatments. These parameters were used in evaluating the hydraulic fracture treatments.

Fracture treatment

The fracture closure pressures and leak-off coefficients, obtained from the mini-fracs, were included in history matching the actual fracture treatment. As discussed previously, if the pressure response during the fracture treatment could be history matched accurately, then the predicted fracture geometry should also be reasonably accurate.

As shown in Fig. 2b, the "net pressure" (modeled) and "observed net pressure" (measured) matched very well for the fracture treatment performed on Well S711. The pressure increase during injection indicated that the tip of the fracture had screened-off, preventing additional fracture propagation. As additional fluid and proppant were pumped into the fracture, the net pressure increased, which increased the fracture width, maximizing the fracture conductivity.

At the end of the treatment, when pumping operations stopped, the pressure declined very slowly, indicating that the fracture was packed with proppant. Fig. 2c details the fracture geometry determined for Well S711 based on the history.

A stress profile for Well S711 was developed using the in situ stress (closure pressure) for the sandstone, determined from the mini-frac pressure decline. The net pressure at the end of the fracture treatment was obtained by subtracting the closure pressure, determined by the mini-frac, from the instantaneous shut-in pressure (Table 2 [52,683 bytes]).

High net pressure, as seen in Well S711, can indicate that the fracture is packing off with proppant. The wells with low permeability (S708 and S668) had very low net pressure at the end of the treatments, indicating that the wells were not approaching a pack-off condition.

The high net pressure in Well S677 was caused by the fracture screening out. The net pressure on Well S727 could not be determined most likely because the surface pressure went to zero after the screenout because a valve opened on surface released the pressure. Effective stimulation of high-permeability formations requires short, high-conductivity, propped fractures.1 2 The propped fracture lengths designed for all of the Soldado treatments were relatively short, ranging from 52 to 97 ft.

As shown in Table 3 [50,777 bytes], the conductivities of all the fracture treatments were relatively high, from 7,200 to 24,100 md-ft. Therefore, the high permeability formations (S711, S677, and S727) should have been effectively stimulated by the designed fracture treatments. However, the lower permeability formations (S708 and S668) may have been more effectively stimulated by longer fractures with lower conductivity.

Analyzing the mini-frac and hydraulic fracture treatment data indicates that short, high-conductivity fractures were created. The next step was to review the pressure build-up data to determine completion efficiency.

Pressure build-ups

Table 4 [153,740 bytes]summarizes the pressure build-up analyses, and Fig. 3 [48,308 bytes] compares post-completion skin factors for both the frac pack and gravel-pack completions.

Wells completed with frac packs had consistently lower skin factors than wells completed with gravel packs, as seen in Fig. 3.

Fig. 4 [47,814 bytes]shows that the post-completion skin factor is a function of reservoir permeability. For both the gravel pack and frac-pack completions, the skin factor increases with increasing reservoir permeability.

Skin factors greater than zero in frac-pack completions may mean that the dimensionless fracture conductivity is insufficient to effectively overcome all of the near well bore damage in the high-permeability intervals. In many cases, it may be impractical to increase the fracture conductivity sufficiently to obtain a negative skin factor.

Several recently published case studies are consistent with these results. Post-completion skin factors for frac-pack completions are consistently lower than conventional gravel-pack completions, but the skin factors for wells completed with frac packs are not always negative.^3-6

One study showed that the average skin factor for gravel-pack completions was +21, and the average skin factor for frac-pack completions was +0.4.

Another technique to evaluate the effectiveness of frac packed and gravel-packed completions is to compare completion efficiencies. A completion efficiency greater than one implies some damage, and a completion efficiency less than one implies the well is stimulated.

Fig. 5 [46,714 bytes] shows the cumulative frequency distribution of the completion efficiency for the wells with pressure build-up tests. Although this study was statistically limited by a small data set, the data trends were instructive. The results showed that the frac-pack wells had a 70% chance of achieving a completion efficiency of greater than 80% compared to the gravel packs with only a 32% chance.

The pressure build-ups indicate that flow regimes dominated by hydraulic fractures (linear or bilinear flow) are not evident, even for well tests indicating a slightly negative skin. This is typical of high-permeability formations, where these early time flow regimes are masked by well bore storage.

Completion effectiveness

The 3D fracture modeling indicated that frac-pack completions in the Soldado field have short, highly conductive propped fractures.

Post-completion pressure build-up analysis indicated consistently lower skin factors for wells completed with frac packs as compared to those completed with gravel packs. The pressure build-ups showed some frac-pack wells have skin factors greater than zero.

Post-completion performance

Poor completions were ruled out as an explanation for the lower-than-expected well performance. Pressure build-ups and production data were used to evaluate the reservoir characteristics that control well performance.

As summarized in Table 4, the productivity index, PI, was calculated using production rate, average reservoir pressure, and flowing bottom hole pressure determined from each pressure build-up test.

Fig. 6 [46,946 bytes] shows the PI as a function of transmissibility (kh/µ) for frac-pack and gravel-pack completions. A positive correlation exists, as expected. The frac-pack well PIs are slightly greater than the PIs of the gravel-pack wells.

Also note the wide range in PIs and transmissibilities. This can help explain the wide range in well performance.

Even wells with high productivity may perform poorly because of the influence of reservoir boundaries or low reservoir pressure, as determined from the pressure build-up tests. Pressure build-up analyses detected one or more barriers in 7 of the 13 wells.

To illustrate several important points regarding the productivity of these wells, well production histories for three of the frac-pack wells (S711, S722, and S727) are plotted in Fig. 7 [89,145 bytes].

Fig. 6 shows that Well S711 has high transmissibility and PI. Even though it has high transmissibility, it produces less than 150 st-tk bo/d (Fig. 7a) because of its low reservoir pressure gradient (0.25 psi/ft). Thus, the performance of this well is not controlled by the well completion but rather by reservoir pressure.

Fig. 7b is the production graph for Well S727 prior to the frac pack. The initial production of 800 st-tk bo/d declined rapidly, most likely because multiple barriers exist near the well, as indicated by pressure build-up analyses.

Well S722 has both low productivity and transmissibility (Fig. 6). The initial production of 200 st-tk bo/d (Fig. 7c) declined rapidly to less than 80 st-tk bo/d. This is consistent with low transmissibility intervals.

The combined production for five wells with the lowest transmissibilities (S639, S668, S708, S721, S722) is currently less than 250 st-tk bo/d.

Post-completion well performance is influenced by many factors, including skin factor, reservoir permeability and thickness, reservoir fluid properties, the level of depletion, the lift mechanism, and the presence or absence of barriers. For the Soldado field, frac-pack techniques provided high-efficiency completions compared to gravel packs, but many of these wells have low transmissibilities that lead to poor well performance.

Even the wells with high transmissibilities and PIs can be influenced by the presence of barriers and/or reservoir depletion, and thus perform poorly.

In the Soldado field, the reservoir pressure and fracture closure pressure varied over a wide range. The frac-pack completions have resulted in a lower average skin factor (+2.7) than found with gravel packs (+44.0).

Low transmissibility, low reservoir pressure, and/or the presence of barriers can explain lower-than-anticipated well performance.

Acknowledgment

The authors thank their respective companies for permission to publish this article and Frederic Guinot for his mathematical review of the probability calculations that were important to this study.

References

1. Tiner, R. L., Ely, J.W., and Schraufnagel, R., "Frac Packs-State of the Art," Paper No. SPE36456, SPE Annual Technical Conference and Exhibition, Denver, Oct. 6-10, 1996.

2. Bruggeman, J.L., de Vinck, B., van Domelen, M.L., and Bossier, J.C., "Frac-and-Pack Completions of Low-Permeability Formation in West Africa," Paper No. SPE31112, SPE International Symposium on Formation Damage Control, Lafayette, La. Feb. 14-15, 1996.

3. Badgett, K.L., Crawford, G.E., Mills, W.H., Mitchell, S.P., and Vinson, G.S. III, "Using Pressure Transient Analysis to Improve Well Performance and Optimize field Development in Compartmentalized Shelf Margin Deltaic Reservoirs," Paper No. SPE36542, SPE Annual Technical Conference and Exhibition, Denver, Oct. 6-9, 1996.

4. Stewart, B.R., Mullen, M.E., Ellis, R.C., Norman, W.D., and Miller, W.K., "Economic Justification for Fracturing Moderate to High-Permeability Formations in Sand Control Environments," Paper No. SPE30470, SPE Annual Technical Conference and Exhibition, Dallas, Oct. 22-25, 1995.

5. Mathis, J.P., and Saucier, R.J., "Water-Fracturing vs. Frac-Packing, Well Performance Comparison and Completion Type Selection Criteria," Paper No. SPE38593, SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 5-8, 1997.

6. Powell, K.R., Hathcock, R.L., Mullen, M.E., Norman, W.D., and Baycroft, P.D., "Productivity Performance Comparisons of High Rate Water Pack and Frac-Pack Completion Techniques," Paper No. SPE38592, Annual Technical Conference and Exhibition, San Antonio, Oct. 5-8, 1997.

The Authors