As shown by fracturing results in an Egyptian field, operators should consider pressure-depleted wells as fracture candidates to boost existing production and extend the economical life of wells and fields.
In the fracturing of these zones, a primary objective is to control high spurt leakoff by using higher injection rates to outrun fluid leakoff to the depleted formations. These pressure depleted formations offer the unique advantage of boundary layers acting as fracture-containment barriers because of the differential pressure between the boundary shales and the pay zone.
Fracturing provides accelerated production, bypasses of any skin damage, and possible increases the recoverable reserves by linking higher pressured sand stringers to the fracture.
The work in Egypt involved hydraulic fracturing oil wells that had produced for about 27 years. In these wells, the bottomhole reservoir pressure (BHP) had decreased from the initial 4,500 psi to the current 1,000-1,500 psi.
The producing formation in these wells is predominantly a 40-50 ft sandstone with multiple shaly-sand stringers encompassing a 150-ft gross thickness. Formation permeability ranges from 1 to 25 md.
Selecting the wells
In Egypt, Gulf of Suez Petroleum Co. (GUPCO) oil production peaked at more than 600,000 b/d in the mid-1980s and has since declined to less than 200,000 b/d as fields have matured. The Western Desert acreage was among the most mature provinces in the company's portfolio with over 27 years of production.
The company recognized that increasing increment production required new approaches and formed a multi-disciplinary team with members from GUPCO and the service companies to review the candidate inventory and develop a plan.
The team reviewed 30 wells against predetermined selection criteria including sand quality, structural position, pressure performance, remaining reserves, etc.
In the next step, it ranked the candidate wells by the highest potential for success. This effort yielded the selection of 12 suitable wells for hydraulic fracturing. GUPCO pursued all 12 wells, but this article reviews the performance of the 5 wells in the program.
The program began with the highest-ranking wells, but the treatment in the first well had limited success. Well-preparation difficulties influenced the ability to fracture the desired interval in the well. The treatment did fracture another zone, but the results were less successful than predicted.
Subsequent wells and the short learning curve, however, helped shape the remainder of the program for a successful operation.
The program included fracturing a minimum of three wells, so that poor results in the first well did not prevent the treatment of more wells.
Hydraulic fracturing
Hydraulic fracturing of pressure-depleted wells has many similarities to fracturing both low and high-permeability zones. In these wells, it is often difficult to generate sufficient fracture width to place high proppant concentrations.
Fracturing high-permeability wells normally involves creating a short-wide highly conductive path back to the wellbore. These jobs do not require extended fracture lengths.
Jobs in low-permeability wells, on the other hand, try to establish the maximum economical fracture length.
In fracturing a pressure-depleted zone, one should design fracturing parameters to establish the maximum fracture length that links several sand stringers into one dominant fracture plane. A pressure-depleted fracture behaves as a high-permeability well during the fracture operation and a low-permeability well during the production phase.
Another similarity to the high-permeability formations is the excessively high fluid-loss rates to the formation.
Controlling the fluid leakoff rate is the single most important factor for achieving success in fracturing pressure-depleted reservoirs.
Extensive experiments show that fluid-loss behavior changes significantly with changes in formation permeability and the pressure drop that drives the fluid loss. The pressure drop is the difference between bottomhole treating pressure and bottomhole reservoir pressure.
Water-soluble particulate material along with viscous gel invasion into the matrix control the fluid loss inside the fracture. In pressure-depleted formations, the differential pressure driving the fluid leakoff is considerably higher than normal low-permeability formations.
For high leakoff reservoirs, the steady-state leakoff rate is often more than half of the total injection rate.1
In general as permeability increases, spurt loss increases significantly but the filter cake (wall-building) coefficient (Cw) remains relatively constant. This suggests that in oil and gas wells with greater pressure depletion, the spurt loss is a critical parameter that must be taken into account when analyzing minifrac data and when designing the main fracture treatment.
The wells in the program had a high fluid spurt loss ranging from 0.65 to 0.85 gal/sq ft and a Cw value of 0.0035 fpm1/2.
The jobs used injection rates of 35-50 bbl/min to outrun the high fluid leakoff. These high rates created a differential pressure inside the fracture so that adequate fracture widths would develop.
One advantage to fracturing pressure-depleted wells is that overlying or underlying shale formations provide a pronounced fracture containment barrier because of the depletion of the sand-producing interval. The rock stresses in the boundary layers are reduced, but not to the same extent as the producing interval. In the wells in Egypt, this resulted in a 2,000-3,000-psi differential stress gradient between the rock layers.
The fracture operations could be carried out with confidence because horizontal fracture penetration is the easiest path for the fluids to follow rather than paths downward and out of the pay zone.
Full fracture containment from above and below allows the operator to focus more on the fracture length. This allows for jobs with large tubular fracture strings that allow sufficient injection rates, if needed, to outrun the fluid leakoff.
The economic success of hydraulic fracturing treatments will depend on obtaining proper fracture placement and sufficient fracture conductivity within the proppant bed.2
Fracture fluids
Recent developments in fracturing fluid technology enable operators to place larger, wider, and longer fracture treatments that potentially improve post-frac oil production.3 Also fluid testing actual source samples and real-time monitoring allow the operator to maintain a consistent fluid throughout the treatment.
The fracture fluids used in Egypt consisted of a high-pH delayed borate crosslinked fluid system at 250° F., with a polymer gel loading reduced to 35 lb/1,000 gal from 40 lb/1,000 gal. Several Model-50 (Fann viscometer) tests analyzed the polymer.
Tests sampled various gel loadings along with breaker concentrations to ensure a stable crosslinked gel during injection and an aggressive quick gel break within 30 min after job placement. Also several emulsion tests determined any incompatibilities between the fracture fluids and the formation crude oil.
In the design, several surfactants were tested to ensure full emulsion breaks and rapid phase separation. This promotes a more-complete break and cleanup of the treating fluids for improved fracture fluid recovery and better well productivity.
Calculated friction loss with a 4 1/2-in., PH-6 fracture string was 0.30 psi/ft (3,000 psi for a 10,000-ft column).
The selected fluid system provides a delayed crosslinked gel viscosity of 800-1,000 cp. Fluids were delayed crosslinked about halfway down the 10,000-ft tubing string to reduce pipe friction.
The fluids greatly improved proppant transport with high proppant concentrations because the polymer reheals after being sheared through the perforations or retrievable fracture tool string. This allows the proppant to be transported deeper into the fracture before the crosslinker breaks.
Minifrac analysis
Experience among stimulation engineers and the use of quick, low-cost injection tests can often turn potential premature screenouts into a completed-as-planned fracture treatment.4
One can derive from minifrac tests prior to the propped fracture treatments such key design parameters as leakoff coefficient, closure stress, closure time, fluid efficiency, spurt loss, fracture length, width, height, and net fracture pressure.5
From experience, it is important, especially in the case of high permeable and high-leakoff rate designs, to determine these parameters as accurately as possible because errors will enhance the chances of a premature screenout of the propped fracture treatment.6
With limited reservoir information, minifrac tests greatly assist the design process by optimizing fluid and proppant volumes required for the main fracturing treatment. In Egypt, all wells included a minifrac treatment and fluid volumes sufficient for full vertical pay-zone coverage.
Spurt losses in high-permeability or over-stressed, pressure-depleted reservoirs can be significant and can cause misleading results in standard minifrac analysis. In the analysis, one should consider spurt time and volume where spurt is dependent on volume pumped and the pumping time.
The minifrac process requires the use of a full 3D fracture simulator model to simulate the fracture growth from initiation to completion of the treatment. Based on input parameters of reservoir properties, fluid and proppant volumes, and rates of injection, the model predicts the fracture length, width, and fracture height.
In addition to the fracture model, a prefracture reservoir simulator aids in determining the type of treatment required by evaluating the simulated post-fracturing production. This simulator enables a quick sensitivity analysis and results comparison based on evaluating the effects of the fracture length and fracture conductivity using reservoir conditions.
Real-time monitoring of the net pressure rise throughout the fracture treatment enables the operator to predict a screenout before it occurs.
The minifrac analysis in the wells in Egypt showed a fluid efficiency (FE) of 18%. With the low FE, the analysis calculated that the jobs required a 50-60% pad volume to place the fracture treatments successfully.
Viscous gel pills are one option for reducing the chance of creating multiple fractures in multiple layered, pressure-depleted formations. These pills help control fluid loss to the depleted pores, helping to establish a single, dominant fracture.
The program in Egypt included proppant slugs pumped in the pad stage on a few wells that displayed the highest fluid leakoff rates determined from the minifrac. The proppant slug provided both a scouring effect to smooth out a path into the dominant fracture and also helped reduce high spurt loss to provide better fluid-loss control inside the fracture.
One must note that viscous gel pills and proppant slugs are options used to help combat extreme cases of high fluid leakoff and to create a single dominant fracture. The work in Egypt did not indicate the development of any multiple fractures during the treatments.
All wells in the program were nearly vertical, with 7° being the highest wellbore deviation.
The step-down test on the first two wells determined the existence of any near-wellbore restrictions.
The perforating program can have a significant effect on the success of preventing, or at least reducing, the severity of near-wellbore problems during fracture-stimulation treatments.7 In Egypt, the program reperforated all fracture candidate wells with big-hole charges (0.75 in.), 60° phasing, and six shots/ft. This provided good communication between the wellbore and formation.
The program did not encounter any proppant-entry restriction problems.
Fracturing design
As previously discussed, techniques and objectives for fracturing high-permeability formations are different from those for low-permeability formations. Controlling fluid leakoff is a paramount consideration when fracturing low-permeability pressure-depleted wells. Ideally, to maintain fracture conductivity, it is better to increase injection rate to control high leakoff rates rather than load the fracture with particulate-type fluid-loss additives.
Pressure depleted wells act as high permeability wells during the fracture operation and the objective for fracturing these wells is to create extended fracture lengths in a high-permeability operational environment.
In wells where high leakoff is a concern, special considerations should be given to achieving a screenout design. The purpose is to optimize the fluid inside the fracture and create maximum conductivity. Proppant concentrations of 8-10 ppg will normally dehydrate or bridge-off inside the fracture, creating this tip screenout effect. Final propped fracture concentrations at the wellbore often exceed 3.0 lb/sq ft.
To ensure the success of a fracture treatment, one needs to select candidate wells carefully with consideration given to remaining reserves, reservoir engineering, magnitude of pressure depletion, reservoir parameters, and operational aspects of the fracture treatment.8
Many operators often discount fracturing pressure-depleted wells as a non-economical approach to increasing oil production. But with oil prices above $20/bbl, these treatments are economical in wells that exhibit sizable net sand thickness, marginally pressure-depleted formations, and formation fines migration damage due to years of production.
Potential two to five-fold production increases are possible in the best candidate wells.
Fracturing results
Five cases show the type of results attainable by fracturing pressure-depleted formations.
In Case 1, the well originally produced at a 635-bo/d rate. After the fracturing treatment, production increased to 1,875 bo/d, a 1,240-bo/d gain.
Fig. 1 displays the fracture treatment chart for Case 1, and Fig. 2 is a simulation of the expected production from the well with and without the fracturing treatment. The actual well production is shown in Fig. 3.
In Case 2, the well originally produced at a 226-bo/d rate. After the fracturing treatment, the well produced 900 bo/d, a 674-bo/d gain. During the treatment, the fracture screened out with 4,700 gal out of 6,500 gal displacement pumped. Fig. 4 displays the treatment chart.
In Case 3, the well originally produced at a 495-bo/d rate. After the fracturing treatment, the well produced 755 bo/d, a 260-bo/d gain. During the treatment, the fracture screened out with 5,600 gal out of 6,500 gal displacement pumped.
In Case 4, the well originally produced at a 216-bo/d rate. After the fracturing treatment, the well produced 1,063 bo/d, a 847-bo/d gain.
In Case 5, the well originally produced at a 85-bo/d rate. After the fracturing treatment, the well produced 400 bo/d, a 315-bo/d gain. This well is the only well in the program with formation bedding planes dipping at 30° to the wellbore. Also the well is about 10 km away from the main field.
As shown by these results, this program was a good operational, production, and economical success. Table 1 compares the fracturing properties derived from the FracproPT 3D fracture simulation model and Table 2 summarizes the treatments.
Acknowledgments
The authors thank Gulf of Suez Petroleum Co. (GUPCO) and Halliburton Energy Services for permission to prepare and publish this article. F
References
- McDaniel, B.W., Stegent, N.A., and Ellis, R., "How Proppant Slugs and Viscous Gel Slugs Have Influenced the Success of Hydraulic Fracturing Applications," Paper No. SPE 71073, SPE Rocky Mountain Petroleum Technology Conference, May 21-23, 2001.
- Parker, M.A., and McDaniel, B.W., "Accurate Design of Fracturing Treatment Requires Conductivity Measurements at Simulated Reservoir Conditions," Paper No. SPE 17541, SPE Rocky Mountain Regional Meeting, Casper, Wyo., May 11-13, 1988.
- Conway, M.W., McMechan, D.E., McGowen, J.M., Brown, D., Chisholm, P.T., and Venditto, J.J., "Expanding Recoverable Reserves Through Refracturing," Paper No. SPE 14376, 60th SPE Annual Conference and Exhibition, Las Vegas, Nev., Sept 22-25, 1985.
- Tan, H.C., McGowen, J.M., Lee, W.S., and Soliman, M.Y., "Field Application of Minifrac Analysis to Improve Fracturing Treatment Design," Paper No. SPE 17463, SPE California Regional Meeting, Long Beach, Calif., Mar. 23-25, 1988.
- Parker, M.A., and McDaniel, B.W., "Fracturing Treatment Design Improved by Conductivity Measurements Under In Situ Conditions," Paper No. SPE 16901, SPE Annual Conference and Exhibition, Dallas, Sept. 27-30, 1987.
- Rollins, K., and Hyden, R.E., "Pressure-Dependent Leakoff in Fracturing—Field Examples from the Haynesville Sand," Paper No. SPE 39953, SPE Rocky Mountain Regional Meeting, Denver, Apr. 5-8, 1998.
- McDaniel, B.W., McMechan, D.E., and Stegent, N.A., "Propper use of Proppant Slugs and Viscous Gel Slugs Can Improve Proppant Placement During Hydraulic Fracturing Applications," Paper No. SPE 71661, SPE Annual Conference and Exhibition, New Orleans, Sept. 30-Oct. 3, 2001.
- Hunt, J.L., and Soliman, M.Y., "Reservoir Engineering Aspects of Fracturing High Permeability Formations," Paper No. SPE 28803, SPE Asia Pacific O&G Conference, Melbourne, Australia, Nov. 7-10, 1994.
Based on a presentation to the Mediterranean Offshore Conference and Exhibition, Alexandria, Egypt, Apr. 9-11, 2002.
The authors
Ahmed Moustafa Ezzat heads the Western Desert area department for GUPCO in Cairo. Part of his job includes the frac program for the Western Desert wells. Ezzat has a BS in petroleum engineering from Al-azhar University.
Thomas L. Rut is division manager, Western Desert and Gulf of Suez south for GUPCO in Cairo. He previously worked for other BP PLC's joint ventures in Kuwait and Alaska. Rut has BS in petroleum engineering from the University of Texas.
Rob Poole is a stimulation-completions consultant with Natchiq Technical Service in Houston. He previously worked in various capacities for Halliburton Energy Services. Poole has a BS from Montana Tech.
