Indirect fracs, frac packs successfully stimulate Saudi unconsolidated gas formations

May 10, 2004
Saudi Arabian Oil Co. (Saudi Aramco) successfully applies various fracturing programs in its pre-Khuff sandstone formation ('Unayzah and Jauf reservoirs), including indirect fracs and frac packs to stimulate unconsolidated gas zones.

Saudi Arabian Oil Co. (Saudi Aramco) successfully applies various fracturing programs in its pre-Khuff sandstone formation ('Unayzah and Jauf reservoirs), including indirect fracs and frac packs to stimulate unconsolidated gas zones.

The fracturing programs include:

  • Direct, conventional fracturing in competent rocks.
  • Indirect fracturing in a competent reservoir interval, which has an intermixing of consolidated and unconsolidated sandstones.
  • Frac packs for highly unconsolidated intervals encountered throughout the reservoir.

The primary purpose of all propped fracturing is the control of sand production with a secondary objective of production enhancement.

The wells in these reservoirs are prolific and, depending upon reservoir conditions, can deliver about 20-100 MMscfd of rich gas while maintaining high wellhead pressure.

To date, the fracturing program has included more than 15 wells completed with frac packs and more than 50 wells completed with indirect fracturing.

'Unayzah reservoir

The Upper 'Unayzah reservoir unit, was deposited in an eolian depositional environment where the primary reservoir facies are the dune and sheet sand deposits.1 The dune sands of Upper 'Unayzah reservoirs are well rounded, well sorted, and composed primarily of quartz grains with rare feldspars.

Geologists classify these sandstones as very mature based on textural and mineralogical properties.

From a reservoir point of view, dune sands have superior reservoir flow capacity. At the time of deposition, dune sands can have porosity and permeability values greater than 35% and 5 darcies, respectively.

In general, reservoir quality deteriorates as a function of depth of burial and time. The 'Unayzah formation has much greater porosity and permeability than what one would expect from a 350-million-year-old reservoir buried at depths exceeding 14,000 ft.

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In some deeper fields, the 'Unayzah reservoir exhibits porosities greater than 25%. In addition to this higher-than-expected porosity, the reservoir often is very friable and unconsolidated (Fig. 1). This adds a tremendous challenge and complexity to the drilling, completion, and production of the reservoir.

The portion of reservoir rocks that appears solid (Fig. 1a) falls apart when held tightly in the hand.

Cementation is the key to reservoir consolidation. Quartz cemented sandstones that are characteristic of the Lower 'Unayzah reservoirs tend to be well consolidated (hard) and can withstand drilling and completion procedures with little chance of unconsolidated sand affecting the completion.

Reservoir sandstones cemented with clay (illite) tend to be friable to unconsolidated in nature. Illite, a very weak cement, when present prevents any other cements from being formed, and once hydrocarbons move into the reservoir, cementation stops completely.

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Fig. 1b illustrates x-ray diffraction of illite-coated sand grains that are easily friable in Upper 'Unayzah section.

Jauf reservoir

The Jauf reservoir has permeability and porosity variations and exhibits unconsolidation intermingled with consolidated sandstone. The high-permeability layers, which are usually unconsolidated, have excellent flow capacities.

The Jauf formation has shore face, estuary, and shallow marine sandstones deposited during a period of sea level fluctuations on a shallow shelf. The marine regressive phases gave rise to wave-dominated shore face and strand plain deposits, while tide-dominated estuaries and barrier-lagoon systems characterize the transgressive phases. Estuarine sands including barrier-bar, and ebb and flood tidal channel sandstones form the best quality reservoir sandstones.

The Jauf reservoir sandstones primarily are of quartz with varying amounts of framework and pore lining clay. Along with quartz, feldspars such as orthoclase and microcline are present in some sandstones and are absent in others.

The entire section thus exhibits sandstone to a varying degree of consolidation.

Formation properties

Formation intervals composed of relatively stiff rocks are primary load bearing members in the pre-Khuff stratigraphic section. That is, for intervals possessing greater stiffness, these intervals can accommodate more of the lateral load than the less-stiff softer formations with the same boundary loading.

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A series of studies and calibrations led to the development of equations and correlation factors that represent stress magnitude and rock stiffness and their inter-relationship and dependency on each other (See equation box).2 3

The studies used Young's modulus and Poisson's ratio computed from openhole logs (dynamic values) that were calibrated with laboratory-measured core data under in situ conditions to obtain static values. The horizontal stresses were calibrated to minifrac and borehole image data to compute horizontal stress magnitude to be described with constant strain values, ε1 and ε2.2 The model is used extensively for predicting geomechanical properties in gas reservoirs.

Parallel to the stress equation, Saudi Aramco developed a sand-prediction model to compute formation failure and the onset pressure for sand production in both moderately and highly unconsolidated formations.3 4

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Similar to the stress equation, this model required extensive data and calibration coefficients. Numerous laboratory tests on representative core samples from different fields and under in situ stress conditions (pressure and temperature) determined hollow cylinder and unconfined compressive strengths and the relationship between them. Tests under different fluid saturations show the impact of a fluid on sand consolidation properties. These values are used in the geomechanical model to predict the nature of reservoir rocks using drilling and openhole log data.

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This model computes safe drawdown pressure (SDP) under which the reservoir will produce sand-free. The examples in Figs. 2-4 show the mechanical properties (laboratory measured and model predicted) and actual sanding occurring during production plotted against model predicted values. The results show the usefulness and validity of the developed model.

The geomechanical model computes maximum and minimum in situ horizontal stresses. Reservoir analysis has shown that the rock stress is strictly related to rock stiffness.

The borehole image data (Fig. 5) show breakouts in stiffer, hard rock intervals and lack of breakout in softer, less-stiff intervals.
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The stiffer intervals where breakouts occur have higher minimum horizontal stress, thus higher σH/σh ratio. In the softer intervals with low σH/σh ratio, washouts dominate and are more prominent.

Indirect fracturing technology

Saudi Aramco bases the proper candidate selection for indirect fracturing on reservoir flow and mechanical properties of a particular well. A candidate well should have:

  • 20-40 ft a single, of consolidated interval for placement of perforations.
  • Reasonable standoff between perforation interval and friable, unconsolidated zone.
  • Minimum stress barrier between consolidated and unconsolidated zones so that a fracture can propagate into the soft formation once initiated in the competent interval.
Fig. 6 shows an indirect fracture candidate well where the selected perforation interval is in the higher in situ stress zone (Track 1).
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Track 2 shows the minimum and maximum in situ stress values, and Track 3 shows the unconfined compressive strength and safe drawdown pressure.

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Fig. 7 shows the expected vertical coverage of the propped fracture into the unconsolidated zone as computed from history matching the actual data.5

Frac pack technology

Saudi Aramco introduced frac pack technology as an alternative to control sand production. This technology was adopted as a completion scheme for:

  • Minimizing proppant damage caused by the flowback of solid control additives used during indirect or conventional fracturing.
  • Reducing partial penetration effects.
  • Completely eliminating proppant or solid flowback.

Saudi Aramco uses the technology exclusively in wells in which the reservoir consists only of friable sand and in which indirect or conventional fracturing cannot prevent sand production.

The method employs high-quality material for the screens and completion assembly so as to withstand in situ conditions such as pressure, temperature, corrosion effects, and a high gas rate.

The correct implementation of the technique requires engineers and geoscientists to solve several technical issues and complications on a day-to-day basis. These issues require the use of best practices in:

  • High pressure, high-temperature completion fluids.
  • Perforating techniques (direction, type, size, and penetration, and density).
  • Perforation intervals for optimal coverage.
  • Kill-pills to neutralize a well incurring minimal damage.
  • Optimized fracture design and skilled execution.
  • Careful choice and expert manipulation and management of downhole completion equipments during treatment procedure.
  • Quick and effective cleanup procedure.

To accomplish these tasks, Saudi Aramco has set up a special team of technical experts from drilling and well construction, production operations, reservoir engineering and management, and stimulation specialists who assure quality work and procedures during the entire well completion process.

Current practices include use of phased perforation with 18-21 shots/ft (large size) placed directly in the main porosity interval, about 1,000 lb of proppant/ft of perforated interval, optimized pad volume, and moderate proppant concentration scheduling so as to avoid hard screen-out and attain sufficient net pressure at the end of the treatment.

Frac pack recommendations

From research and experience, the team has developed the following recommendations and general guidelines as best practices for a frac pack completion.

  • Choose appropriate candidate. For this, reservoir permeability.3. thickness (kh), sand strength and consolidation, interval thickness, reservoir fluid conditions, etc. have to be thoroughly evaluated and analyzed.
  • Use low pad volume for treatment design to avoid formation damage.
  • Use moderate proppant concentration and ramping to generate a gradual, but high level proppant pack.
  • Carry datafrac treatment to ensure fluid quality, fluid loss, and closure pressure. Accuracy may require more than one datafrac, but only in new areas.
  • Carefully calculate tip-screenout time because this is essential for implementing a successful frac pack treatment. Pre-compute how much net-pressure is needed for penetration, vertical coverage, successful packing, and required conductivity.
  • From the datafrac evaluation, redesign and calibrate main treatment and calculate anew fracture dimensions and conductivity to ensure that these values meet the objectives.
  • Do not overestimate fluid loss by selecting early slope changes in shut-in pressure graphs from datafrac analysis because this may lead to using higher than needed pad volume and consequently undermining good proppant packing and ultimate conductivity. Monitor downhole temperature and account for heat effects on fluids while analyzing datafrac.
  • Always target net pressure as high as possible for strengthening reservoir near well and for better fluid communication
  • Use downhole pressure gauges or live-annulus for pressure data. Analyze such data instead of wellhead measurements for accuracy.
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Fig. 8 shows a frac pack treatment in the 'Unayzah formation. This well has two major, thick producing intervals with porosity varying between 15 and 30%. The sand intervals are extremely friable (Track 2 on the log shows sanding with any drawdown pressure) with very high permeability and tremendous gas and condensate potential.

The frac pack consisted of two stages, a total proppant mass of about 80,000 lb, and a highest concentration stage of 8-lb proppant added to 1 gal of fluid (ppa).

Well performance

Post-fracture production tests have confirmed the effectiveness of both indirect fracturing and frac packs.

Saudi Aramco routinely tests wells after fracturing and many are currently hooked up for continuous supply of gas to the mega-capacity plants.

All wells feeding the gas plants have high sand-free production rates that testify to the success of the technology.

Fig. 9 shows the consistent rates achieved by wells stimulated with frac packs and indirect fracturing.
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Saudi Aramco currently deals with various formation types, and many different stimulation and completion techniques are required to meet its high gas demand.

With technical advancement and new discoveries, it also is evaluating other options such as multilaterals and horizontal laterals in conjunction with well stimulation.

References

1. Rahim, Z., et al., "Saudi Aramco Implements its First Screen, Frac Pack Stimulation Completion in the Unconsolidated 'Unayzah Reservoir to Eliminate Sand and Enhance Gas Production," Saudi Aramco Journal of Technology, Fall 2003.

2. Al-Qahtani, Y.M., and Rahim, Z., "A Mathematical Algorithm for Modeling Geomechanical Rock Properties of the Khuff and Pre-Khuff Reservoirs in Ghawar Field," SPE Paper No. 68194," SPE Middle East Oil Show, Bahrain, Mar. 17-20, 2001.

3. Gas Reservoir Management Division, Saudi Aramco, Internal Documentation of Fracturing and Rock Mechanics.

4. Geomechanical and perforation stability modeling—a combined work of Saudi Aramco and ChevronTexaco, 2002-03.

5. Bruce Meyer: "MFRAC—a 3D fracture design and analysis program," Meyer & Associates, Natrona Heights, PA.

The authors

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Zillur Rahim is supervisor of Saudi Aramco's gas reservoir management division special studies and prospects unit. His duties include working as a mentor for the technologist development program that is dedicated to the training of Saudi engineers. Prior to joining Saudi Aramco, Rahim worked with Holditch & Associates Inc., and later with Schlumberger Holditch-Reservoir Technologies in College Station, Tex. Rahim received an MS and PhD in petroleum engineering from Texas A&M University. He is a registered professional engineer in Texas.

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Mohammed Y. Al-Qahtani heads Saudi Aramco's gas production engineering division. He is a reservoir engineering expert specializing in geostatistical modeling, reservoir characterization, reservoir simulation, and phase behavior. Al-Qahtani received his PhD in petroleum engineering from the University of Southern California. He is a member of SPE.

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Kirk Bartko is a stimulation team leader with Saudi Aramco, Dhahran, where his responsibilities involve supporting stimulation and completion applications throughout the company. He previously worked for ARCO. Bartko holds a BS in petroleum engineering form the University of Wyoming.