Petro Kazakhstan improves processes for 2006 hydraulic fracture campaign

April 2, 2007
Petro Kazakhstan Kumkol Resources (PKKR) has increased oil production in five Kazakhstan fields through a hydraulic fracturing program.

Petro Kazakhstan Kumkol Resources (PKKR) has increased oil production in five Kazakhstan fields through a hydraulic fracturing program. The wells had not been fractured when initially brought on line.

Click here to enlarge image

Evaluation of current fractured wells, the candidate selection process, and postfracture completion practices are believed by PKKR and Halliburton to be keys in achieving the sought-after result of significant oil-production increases. PKKR used hydraulic fracture stimulation in five fields, all located just north of the city Kzyl Orda (Fig. 1). Production from the Mayburak field rose 100% immediately afterward (Fig. 2).

Click here to enlarge image

This article presents the methodology followed by PKKR and Halliburton to evaluate, select, and prioritize fracture-candidate wells for the PKKR 2006 fracture campaign.

As of February 2007, PKKR had drilled and completed 591 wells in five Kazahkstan fields that it manages (Kumkol South, South Kumkol, Kyzykiva, Aryskum, and Maybulak), including 74 wells in the past year. The company fracture stimulated 92 of the wells as part of the initial completion process. Of the remaining wells, PKKR selected and fracture stimulated 52 wells (45 producers, 7 injectors) during its 2006 campaign.

Candidate selection

The following steps guided selection of wells for fracture stimulation:

  1. Before expending resources selecting individual wells for hydraulic fracturing, first determine the potential of the field to yield an adequate return on investment (ROI).
    • Calculate the current, radial, and fractured-well productivity index (PI). The PI is the ratio of liquid production rate to the pressure drop at the center of the completed interval.

      PI is a measure of the well’s potential and can be extrapolated to estimate field potential. Conditions such as relative permeability, skin factor, reservoir pressure, and oil viscosity can change throughout well or reservoir life, and can change PI.1
    • Establish cutoff criteria for minimum oil-production increase and water cut.
    • Review nearby wells using well and reservoir analysis software, bubble map, and injection-well locations.
    • Review nearby wells using Halliburton’s OFM well and reservoir analysis software, bubble map, injection-well locations.
  2. Analyze production data from current wells and determine current PI, then estimate postfrac PI.
    • Review current production data, taking note of liquid rate and water cut for the past 2-3 months.
    • Obtain current reservoir pressure from each well, from pressure build up if available, and from fluid dynamic level, from nodal analysis on flowing well, or with direct measurement.
    • Estimate current prefrac PI from liquid rate, reservoir pressure, and bottomhole flowing pressure (BHFP).
    • Calculate the postfrac PI. The prefrac PI can be influenced by well damage, but this is not accounted for in hydraulic-fracture candidate selection. If the well is damaged, the actual incremental increase will be higher than estimated, with the frac treatment more economically attractive.

Preselection criteria

Hydraulic-fracture candidate selection should include only wells that have not been fractured and wells with less than 35% water cut. Other considerations include:

  • Completion history.
  • Workover history.
  • Water-oil contact (WOC), gas/oil ratio (GOR), and bubble point (Pb). If GOR is high and Pb is lower, the well could produce primarily gas and create gas coning.
  • Well location (close to WOC, gas-oil contact, end of reservoir, etc.).
  • Pressure maintenance.
  • Wellbore deviation and azimuth.
  • Fracture plane.
  • Injector-well locations.
  • Oil viscosity. High oil viscosity may cause more drawdown and sand production after frac.
  • Location of faults, natural fissures, or fractures, etc.

Note that if a well is completed in multiple zones or has poor cement bonding across a zone suspected of being water-productive, a workover, including zonal isolation or repair, can possibly allow for an efficient frac in an oil-bearing formation.

Next, calculate the increment increase of oil keeping the water cut value identical to the pre-frac value. (Water cut will normally be higher during the cleanup phase due to losses during workover.)

Finally, sort the wells in order of decreasing tons of incremental oil calculated.

Evaluating logs, maps

Use logs and field maps to evaluate the following information:

Log review of mechanical well condition:

  • Verify operator knowledge of hardware weaknesses that could affect pressure application, such as wellhead limitations, casing leaks, casing weakness, and improperly functioning packers.
  • Verify location of perforated intervals and distance between intervals.
  • Determine presence of water zones or flooded zones near the targeted frac interval.
  • Determine condition of cement to sustain fracture operations.

Review offset wells with field map:

  • Study condition of water-front advancement from nearby wells.
  • Determine whether pressure support is available from injectors in the area.
Click here to enlarge image

Table 1 summarizes reservoir properties for a typical Kazakhstan field operated by PKKR.

Frac design considerations

PKKR completes most wells with 146-mm production casing and uses wellhead isolation tools to protect the wellhead on the surface. Combining retrievable packers and sand plugs enables multiple-zone fracturing, working from the bottom zone upward.

The primary frac fluid used is 30 to 35-lb borate-crosslinked guar/1,000 gal (Mgal) water. If the pay zone is of low porosity or is near a wet sand, however, a 25-lb/Mgal, borate-crosslinked guar fluid is used.

PKKR used an intermediate-strength ceramic, 16/30-mesh proppant, and the proppant schedule was adjusted to optimize the frac design. PKKR ran 35 frac treatments in five PKKR fields in the 2006 campaign.

Click here to enlarge image

A microfrac treatment was run on a well to determine the closure pressures for a shale formation. The procedure provided stress data in one of the fields where the frac campaign would be conducted. Fracture-closure pressure gradient in the shale was found to be 0.184 bar/m. This value is still in use to define shale stress in fracture designs for wells in the field (Fig. 3).

Click here to enlarge image

An injection plus stepdown test (SDT) is normally performed for every job (Fig. 4) in order to:

  • Determine whether the packer is holding frac pressure.
  • Check the communication between wellbore and formation.
  • Determine near-wellbore (tortuosity) friction and perforation friction.
  • Determine closure pressure.
  • Determine the fluid efficiency of the frac-fluid system.
  • Optimize the main frac treatment based on all parameters obtained from injection followed by SDT and minifrac tests.

Pumping a sand slug has proven helpful in removing near-wellbore friction, both from the perforations and near-wellbore area, to help ensure success in placing the main fracturing treatment.

Postfrac procedures

Postfrac completion procedures differ between wells that screen out prematurely and wells that do not screen out early.

Early screen-out wells-if a premature screen-out occurs, begin completion procedures immediately. The worst-case scenario is a screen-out with proppant in suspension from the perforations all the way up to surface.

The gel holding the proppant in suspension will begin to break. Breaking will occur more slowly from the surface to some distance down the wellbore, however, because the temperatures near surface are generally lower than in the reservoir.

When running in the hole with the 42-mm production tubing, PKKR made stops at 300-m increments and reverse-circulated bottoms-up to remove all proppant to that depth. The company repeated this procedure until the tubing had been cleaned out to the tubing shoe.

If the well treatment screens out as planned, PKKR gains several benefits by its postfrac completion procedures that:

  • Reduce production downtime.
  • Limit loss of fluids to the reservoir.
  • Simplify removal of proppant from the wellbore.

The procedures below benefited PKKR’s fracture program.

  1. Shut the well in for a minimum of 12 hr after fracture treatment to allow gelled fluids to break before pulling the packer and swabbing back the injected treatment fluids.

    When closure pressure has declined to a point low enough below the surface pressure to allow fractures to close, completion operations can be started. Note that at this point, there should be no pumping into the formation, nor swabbing from the formation.
  2. Remove the wellhead isolation tool and immediately pull the packer, run tubing in, and begin removal of proppant from the wellbore. Frac fluid may not have completely broken by this time; however, that can be an advantage because less fluid will be lost to the formation during circulation.
  3. To help ensure there is no proppant in suspension in tubing above the shoe, inject into the annulus at least 11/2 tubing volumes of diluted frac fluid, after the packer is released, to circulate proppant that may still be in suspension.
  4. Use leftover 25-30 lb/Mgal base gel and 10-lb/Mgal linear gel to wash proppant out of the wellbore instead of simply disposing the gel. Dilute the base gel with water to about 10 lb/Mgal; this will leave the KCl concentration of 3-4% for the total diluted gel.

    Using diluted gel instead of 2% KCl water as a washout fluid has these advantages:
    • Better proppant-carrying capability.
    • Limited amount of fluid lost to the formation.
    • Lower pumping friction and more efficient proppant cleanout.
    • The high percentage (7%) of KCl in the base gel raises the washout fluid KCl concentration to 3-4%.
  5. Add 1 l. surfactant for every 1 cu m of all fluids used to kill wells and to all fracturing fluids to aid in recovery of fluids lost and help prevent formation of emulsions from mixing of formation oil with completion fluids.

Learnings

PKKR believes that the keys to its successful fracture-stimulation program are well evaluation, candidate selection, and the postfracture completion practices outlined above. The first order of business was to determine the field potential to yield an adequate ROI. Determining the current PI and estimating the postfrac PI were critical steps.

In its 2006 fracture stimulation campaign, PKKR did not include any wells that had been fractured before or wells that had water cut higher than 35%.

Reference

  1. Beggs, H.D., “Production Optimizing Using Nodal Analysis,” Oil and Gas Consultants Int. Inc., Oklahoma, 1991.

The authors

Uzbekbai Yermakhonov ([email protected]) is manager of production engineering at Petro Kazakhstan Kumkol Resources (PKKR). He is responsible for well completions, workovers, and artificial lift installations and has worked at PKKR for 18 years. Yermakhonov graduated (1983) from Satpayev’s Kazakh National Technical University in Almaty.

Karlygash Zhumanova ([email protected]) is a production engineer in the production engineering department of PKKR. He is the coordinator of PKKR’s fracture stimulation project and has worked at the company for 8 years. Zhumanova graduated in petroleum engineering (2004) from Satpayev’s Kazakh National Technical University.

Will Louviere ([email protected]) is a consultant working for Halliburton in Kzylorda, Kazakhstan. He has more than 40 yr industry experience, including about 30 yr with Halliburton Energy Services in all facets of well stimulation. Since 2000, he has worked as a stimulation consultant for various operators in Europe, Russia, the Middle East, and most recently, in Kazakhstan. Louviere holds a BS (1972) in chemical engineering from McNeese State University, Louisiana.

Quinggang Qu ([email protected]) is a principal technical professional assigned to Halliburton’s production enhancement department in Kazahkstan, where he is responsible for stimulation and newly hired engineer training. Qu has 18 years experience in stimulation worldwide. He has a BS (1988) in petroleum geology from China Petroleum University.