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Sunday 24 July 2016

Sand Control and Sand Control Methods

Sand Production


Sand is produced as a result of failure of the formation rock and subsequent mobilisation of the failed material (Tovar and Ibukun 2015). Sand production can lead to production decline as a result of plugging of screens and gravel packs, damaging of pumps and other downhole equipment, erosion of tubing and surface facilities, and in severe conditions loss of the well can occur (Abass, Nasr-El-Din and BaTaweel 2002). The figures below show some damaging effects of sand production.

Sand produced into a separator (gekengineering.com)
a.) screen erosion; b.) surface choke erosion (Matanovic, Cikes and Moslavac 2012) 


Predicting Sand Production


A number of sand failure models have been developed for predicting sand production. Examples of such models are that by Abass, Nasr-El-Din and BaTaweel 2002; and Vaziri et al. 2006.

Sand Control Methods


The major sand control methods used in the industry are briefly described in the following:

1.) Restricting Production Rate:

This is a passive method that involves restricting the well’s flow rate to a level where sand production is at an acceptable rate. Reducing production rate reduces the drag forces on the sand grains (Cholet 2008). The setback of this method is that the maximum sand-free flow rate is usually less than the well’s flow potential, leading to a significant loss in productivity and thus revenue

2.) Selective Perforation:

 This involves perforating only the strong intervals with low sanding tendencies. However, the weaker sands are usually the most productive and this method will reduce well productivity. Also, there is a requirement for the strong intervals to be physically connected to the most productive intervals (Bellarby 2009).

3.) Oriented Perforating:

This involves perforating in the direction with the least sanding tendency based on knowledge of the stress distribution around the wellbore (Sulbaran, Carbonell and Lopez-de-Cardenas 1999). Perforation orientation is along the direction of maximum formation stress (Bellarby 2009, Benavides et al. 2003).

4.) Increasing Flow Area: 

Perforation shot density and size can be increased in cased-hole completions to reduce the flow velocity at the well bore below that required for sand production (Matanovic, Cikes and Moslavac 2012).

5.) Open-hole Standalone Screens (OHSAS): 

In OHSAS, sand screens serve as downhole filtration media for preventing sand production into the wellbore. Exclusion of sand relies upon the formation of a physical bridge over the opening of the screen. OHSAS have suffered significantly high failure rates especially in non-uniform poorly sorted sands. This generally results from plugging of the screen leading to decreased area of flow and consequently, erosion of the screens at ‘hotspots.’


(Weatherford 2001)



6.) Gravel Packing: 

Gravel Packing involves placing gravel within the annulus between the screen and the producing interval where it serves as the primary mechanical filtration media. Gravel Packing is the most popular sand control method with more than 90% of all sand control completions being gravel packs (Petrowiki 2015).

7.) Frac Packs: 

This is a combination of hydraulic fracturing and gravel packing. Fracturing is achieved by pumping a high viscosity fluid above the formation fracture pressure. Proppants are then placed in the fractures created. This technique provides a combination of the benefits of production enhancement of hydraulic fracturing, and sand control associated with gravel packing (Schlumberger 2007). Frac pack requires more complex fluids, and mixing and pumping equipment.

8.) High Rate Water Packs (HRWP): 

HRWP is a cased-hole gravel pack technique where water is used as the gravel carrier fluid. The water pack is performed above the formation fracture pressure. This is not aimed at stimulating the reservoir but to ensure good packing of the perforations with gravel. Water as the carrier fluid ensures high leak off through the fractures, limiting the distance of fracture propagation. HRWP completions have been linked to pack permeability damage caused by fines invading the pack and migrating towards the wellbore (Ali, Vitthal and Weaver 2000).

9.) Chemical Consolidation: 

This technique involves treating the formation in the near wellbore area to improve the bonding of the formation sand grains. Resins are the most commonly used chemicals for sand consolidation and their use requires careful chemical handling. Formation damage caused by the consolidation process can cause an area of reduced porosity and permeability, hence reducing productivity.


Selecting a Sand Control Method


Selection of the appropriate sand control method to be applied in any field development depends on a variety of factors. Some of these are:
  • Cost
  • Required well productivity
  • Reservoir geomechanics: sanding tendency and sanding rate prediction
  • Well geometry or deviation: e.g. challenge with horizontal gravel packing
  • Reservoir fluid properties
  • Expected life of well and well intervention plan
  • Allowable sand production rate
  • Location: easy mobilisation of equipment and personnel; deepwater
  • Technical expertise and experience from offset wells.

An integrated sand management approach that combines both active and passive controls with considerations to the specific requirements of the well, should be adopted in selecting the appropriate method. Oyeneyin (2015) is a good reference for an integrated approach to sand management.

References



ABASS, H.H., NASR-EL-DIN, H.A. and BATAWEEL, M.H., 2002. Sand Control: Sand Characterization, Failure Mechanisms, and Completion Methods. Society of Petroleum Engineers.


ALI, S., VITTHAL, S. and WEAVER, J., 2000. Improvements in High-Rate Water Packing with Surface-Modification Agent. Society of Petroleum Engineers.

BELLARBY, J., 2009. Developments in Petroleum Science, Volume 56 - Well Completion Design. Elsevier.

BENAVIDES, S.P. et al., 2003. Advances in Horizontal Oriented Perforating. Society of Petroleum Engineers.

CHOLET, H., 2008. Well Production Practical Handbook (New Edition Expanded). Editions Technip.

MATANOVIC, D., CIKES, M. and MOSLAVAC, B., 2012. Sand Control in Well Construction and Operation. Berlin, Heidelberg: Springer Berlin Heidelberg, Berlin, Heidelberg.

OYENEYIN, M.B., 2015. Integrated Sand Management For Effective Hydrocarbon Flow Assurance. Developments in Petroleum Science, 63

PETROWIKI, 2015. Sand control techniques. [online] Texas: Society of Petroleum Engineers. Available from: http://petrowiki.org/Sand_control_techniques [Accessed 22 June 2015]

SCHLUMBERGER, 2007. Frac packing: Fracturing for sand control. [online] Texas: Schlumberger. Available from: http://www.slb.com/~/media/Files/resources/mearr/num8/37_49.pdf [Accessed 24 June 2015]

SULBARAN, A.L., CARBONELL, R.S. and LOPEZ-DE-CARDENAS, J.E., 1999. Oriented Perforating for Sand Prevention. Society of Petroleum Engineers.

TOVAR, J. and IBUKUN, O., 2015. Bridging the Gap between Predictions and Reality for Sand Production Prediction. Prediction versus Reality. 26 March 2015. Aberdeen: Sand Management Network.

VAZIRI, H.H. et al., 2006. Sanding: A Rigorous Examination of the Interplay between Drawdown, Depletion, Start-Up Frequency and Water Cut.


Thursday 30 June 2016

Challenging Fields: HPHT Basics

What is HPHT?

In the oil and gas industry, High Pressure High Temperature (HPHT) conditions are generally defined as pressures greater than 10,000 psi and/or temperatures greater than 3000F (1500C). The application of the “and” or “or” in the above definition can be dependent on the geographical region. In Norway for example, only one of the conditions of high pressure or temperature needs to be met for a well to be classified as HPHT while in the UK, both conditions have to be met (Shadravan and Amani 2012).


Some HPHT Fields

The following are examples of some HPHT fields around the world
  • Thunder Horse, Gulf of Mexico (GoM)
  • Kristin Field, Norway
  • Jade Field, North Sea
  • Erskine
  • Tahiti, GoM
  • Elgin
  • Morvin, Norwegian Continental Shelf
  • Jade Field, North Sea


HPHT Tier Classifications

Different companies have come up with tier classifications for categorising HPHT conditions. Whereas the pressure and temperature boundaries adopted may differ, three (3) Tiers are generally employed.
  • Tier I – HPHT
  • Tier 2 – Ultra-HPHT
  • Tier 3 – Extreme HPHT
HPHT Tier Classifications (Baker Hughes & Schlumberger)

HPHT Challenges

The challenges in HPHT development can range from technological to regulatory, HSE and so on. The focus here will be on the technological aspects. In identifying some of these challenges, they will be grouped into drilling, cementing and completions challenges.


HPHT Drilling Challenges

  1. Well Control:
    • Typically narrow drilling window increases the risks of kicks, blowouts or formation fracture

  2. Drilling Fluid
    • Mud rheology properties are affected by the high pressures and temperatures. This can impact the equivalent circulating density (ECD) and hole cleaning ability.
    • Static and Dynamic barite sag
    • Fluid loss
    • Solubility of methane and H2S in oil based mud (OBM)
    • High density muds causing formation damage

Barite Sagging of drilling mud (Shadravan 2012)

3. Low Rate of Penetration (ROP)
    • Typically 10% of the ROP in normal drilling conditions
    • Breakdown of crystal structures in PDC bits
    • Roller-cone bits unsuitable
    • Reliability of MWD/LWD tools reduce at temperatures above 2750F
HPHT Cementing Challenges
    • Physical and Chemical changes in cement due to the high temperatures and pressure
    • Gas migration
    • Strength retrogression at high temperatures
    • Loss of zonal isolation caused by cement shrinking and stress changes due to downhole variations in temperature and pressure.
    • Casing and formation expansion and contraction can cause cracking of already set cement

HPHT Completion Challenges

    • Mechanical integrity of completions components due to hot produced fluids
    • Limitations in density of completion fluids
    • Corrosion of completion components at high temperatures and typically high flow rates
    • Pressure and temperature limits of flow control equipment and electronics
    • High compression loads and pipe movements at packers
    • Thermal cycling and tubing stress
    • Failure of packers and seal materials at high temperatures and pressures
    • Performance of elastomers is reduced by the high temperatures
    • Ignition and detonation of explosive charge for perforation becomes problematic at high temperature. Charges become unstable and may detonate prematurely.
    • Battery temperature limits in intelligent wells
    • Depletion-related sand failure

Suggested Reading

      SPE-163376-MS - HPHT 101: What Every Engineer or Geoscientist Should Know about High Pressure HighTemperature Wells. Available on OnePetro

References

      SHADRAVAN, A. and AMANI, M., 2012. HPHT 101: What Every Engineer or Geoscientist Should Know about High Pressure HighTemperature Wells. Society of Petroleum Engineers.

      DEBRUIJN, G. et al., 2008. Hiph-pressure, High-Temperature Tecnologies. Oilfield Review ed. Schlumberger.

      CUENCA, N., 2015. Challenges in HPHT Wells Available from: https://www.linkedin.com/pulse/challenges-hpht-wells-nicolas-cuenca [Accessed 29 June 2016]

Thursday 16 June 2016

Challenging Fields: Introduction To Deepwater Developments

Deep Water?

In the oil and gas world, the term deepwater can mean different things depending on the discipline. Geologists generally define deepwater with regards to the depositional environment (Slatt 2013). In drilling and well construction, water depths greater than 500m is generally considered as deepwater because the technology requirements above this depth changes (Cuviller et al. 2000). There have been other sub-classifications of deepwater referring to deepwater as depths between 500m and 2000m and Ultra-deep water as depths greater than 2000m.

Deepwater Potential

The potential of deeepwater reserves has been widely recognised. According to the International Energy Agency (IEA) (2013), it is believed that deepwater reserves harbour about a quarter or 300 billion boe of the remaining recoverable conventional oil in offshore fields. Table 1 shows the ultimate recoverable resources for the major producing deepwater regions.


Table 1 Deepwater Resources for Major Producing Deepwater Regions

Deepwater Reservoirs

Deepwater reservoirs are typically comprised of loose unconsolidated sands depending on age, depth of burial and lithology (Ostermeier 1995). Majority of these reservoirs are relatively young geologically and belong to class of formations known as turbidites (Total 2014). Due to their relatively young geological age, deepwater reservoirs generally have good porosities and can be prolific hydrocarbon producers. The nature of deposition of turbidites (Figure 1) results in layers of relatively uniform sands and hence good permeability (Research Triangle Energy Consortium 2010).

Figure 1 Formation of Turbidite Reservoirs (Total 2014)

Deepwater Challenges

These deepwater fields can be challenging in various regards, from the economics to the technological aspects, to HSE. Some of these challenges are highlighted below.

  • They require large investments
  • Large volumes of hydrocarbon producing at high rates are required to offset the large investments
  • Early sand production due to the poorly consolidated nature of turbidite reservoirs
  • Well Intervention is expensive due to high rig costs.
  • Reservoir compaction can occur due to the poor consolidation as the reservoir is depleted.
  • Observations and data acquisition have to be done remotely.
  • The HSE risks are exacerbated due to remoteness from land.


References

CUVILLER, G. et al., 2000. Solving Deepwater Well-Construction Problems. Oilfield Review

INTERNATIONAL ENERGY AGENCY, 2013. Resources to Reserves. International Energy Agency.

NILSEN, T. et al., 2007. Atlas of deep-water outcrops: AAPG Studies in Geology 56.

OSTERMEIER, R.M., 1995. Deepwater Gulf of Mexico Turbidites - Compaction Effects on Porosity and Permeability.

RESEARCH TRIANGLE ENERGY CONSORTIUM, 2010. Deep water completions urgently need innovation. [online] North Carolina: Research Triangle Energy Consortium. Available from: http://rtec-rtp.org/2010/01/25/deep-water-completions-urgently-need-innovation

SLATT, R.M., 2013. Deepwater Deposits and Reservoirs-Chapter 11. Developments in Petroleum Science, 61, pp. 475-552


TOTAL, 2014. Understanding deepwater reservoirs. [online] Paris, France: Total. Available from: http://www.total.com/en/energies-expertise/oil-gas/exploration-production/strategic-sectors/deep-offshore/expertise/understanding-deepwater-reservoirs