August 2007

Reservoir formation failure and sanding prediction for well-construction and completion design

Two North Sea fields overcame sanding problems after detailed rock mechanic analysis and completion designs tailored to the reservoirs' limits.

Vol. 228 No. 8  


Reservoir formation failure and sanding prediction for well-construction and completion design

Two North Sea fields overcame sanding problems after detailed rock mechanic analysis and completion designs tailored to the reservoirs’ limits.

Giin-Fa Fuh, Ian Ramshaw, Kerry Freedman and Nabeel Abdelmalek, ConocoPhillips; and Nobuo Morita, Waseda University

Sand production due to reservoir formation failure often causes significant production loss, facility damage, and can lead to well shut-in after continuous sanding-up. It is cost effective to generate a good well completion design by running a series of computer simulations. Historically, several completion methods were tried for a field. However, this trial-and-error method required time, excessive cost and effort before the best sand mitigation completion method was identified.

Our study showed that, if the reservoir rock strength and its variation along depth were measured for each well, the conditions inducing sand production could be predicted for each interval. Therefore, if permeability distribution and oil and water saturations were measured for each well in addition to the rock strength, the best completion method could be identified without trial-and-error.

Our SAND3D program, a 3D finite element sand production and well mechanics analysis system, has been developed and extensively field-applied over 15 years to predict and handle the onset condition of sand production from the productive interval. This article provides details about our approach and analysis procedures.


The Judy/Joanne field is located in Block 30/07a in the North Sea’s UK sector, within the central graben some 175 mi. east-southeast of Aberdeen, Fig. 1. It is a Triassic gas-condensate field with a hydrocarbon column down to 11,440-ft TVDSS. The development is borderline HPHT with a calculated BHST of 320°F. The main reservoir is the Mid-Upper Triassic-age Joanne sandstone. Hydrocarbons have also been proven and targeted in the Middle Triassic Judy sandstone and the Upper Jurassic Fulmar formation.

Fig. 1

Fig. 1. The Judy/Joanne field is in Block 30/07a of the North Sea’s UK sector.

The field’s pre-Cretaceous wells have been cased and perforated. Some of these are known solids producers that have to be choked back to minimize solids production. To find an improved completion solution for new wells, investigators examined the problem using a systematic rock mechanics approach. Two well cores from Well 30/7a-7 (Judy) and Well 30/7a-P3 (Joanne), provided representative reservoir sandstone samples for sand strength determination and sanding evaluation.


Both cores were sampled and tested using a manual load frame and a penetrometer for unconfined compressive strength (UCS). Further samples were selected from low-to-intermediate strength portions for triaxial tests.

Judy sand strength has 2,000-7,100 psi or higher UCS, Fig. 2. Nearly 50% of the samples tested had UCS lower than 3,000 psi. In the weaker Joanne sandstone, 90% of the samples had UCS below 3,000 psi. About 50% of Joanne sands have UCS from 770-1,500 psi. The P10/P50/P90 values for Judy and Joanne sand strengths are about 2,500/3,000/3,600 psi and 1,000/1,600/3,400 psi, respectively. Sand strength and reservoir depth suggest sand production or sand failure during production, so some control strategy is needed.

Fig. 2

Fig. 2. Unconfined compressive strength work was performed on Judy field’s sandstone cores.


Core segments were selected for triaxial testing and multiple plugs were used to determine stress-strain relationships and failure criteria. Stress-strain relationships were obtained at five different confining pressures: 0, 500, 1,500, 3,000 and 4,500 psi covering the net stress range anticipated over the field’s productive life. These data were then analyzed to define the non-linear material laws and critical plastic strain failure limits for formation failure and sanding prediction, Fig. 3.

Fig. 3

Fig. 3. Stress-strain curve input helped characterize Judy sandstones.

The analysis of stress-strain and rock failure/yield data shows “cap” failure, Fig. 4. Pore collapse failure would occur at high confining pressure for the Joanne sandstone, since it has porosity of 25-32%. The initial shear failure envelope is followed and bounded by a cap representing the onset of pore collapse failure. For the yield envelope, J1 represents the arithmetic sum of the three principal (normal) stresses, while SQRT(J2) represents the generalized shear stress in 3D. Cap failure was not detected and shear failure is projected for the Judy sandstone, due to its tighter nature and 15-25% porosity.

Fig. 4

Fig. 4. The initial shear failure envelope for Joanne sand,
UCS = 1,152 psi, is followed and bounded by a “cap,” representing the onset of pore collapse failure.


Formation failure analysis provides an estimate of failure conditions for particular reservoir rock strengths. Data were gathered and organized into four categories for formation failure and cavity stability modeling:

  • Rock strength
  • Formation stress state
  • Reservoir properties and flow
  • Well geometry and completion plan.

There is a more complex rock failure behavior and mechanism for the Joanne sandstone, i.e., a combination of shear and pore collapse failures. The sandstone exhibits normal shear failure mode resulting from reservoir depletion.

Formation stresses were characterized using well logs, drill stem test, leak-off test, core test, and drilling reports for field wells. In the modeling, the average depths of 11,261-ft TVD and 11,621-ft TVD were used for Joanne and Judy sandstone reservoirs, respectively. The initial stress states are derived or estimated for overburden, maximum horizontal and minimum horizontal stress gradients: Sv = 0.98 psi/ft; Shmax = 0.91 psi/ft; and Shmin = 0 .86 psi/ft. Likewise, the pore pressure gradients of 0.736 psi/ft and 0.728 psi/ft were determined for Judy and Joanne reservoirs, respectively.

Fluid and reservoir permeability was used to determine pressures throughout the grid-blocks and nodes in the reservoir/wellbore system. That allows for prediction of stress changes due to fluid flow and pressure changes. Some of the properties used in the simulation include:

  • K = 20 md (Joanne), 5 md (Judy)
  • Hydrocarbon saturation = 21% (Joanne), 15% (Judy)
  • Gas gravity (relative to air) = 0.74
  • Reservoir temperature = 300°F (Joanne), 320°F (Judy)
  • Porosity = 30% (Joanne), 25% (Judy)
  • Pri = 8,200 psi at 11,261 ft TVD and 8,550 psi at 11,621 ft TVD.

Well geometries from conventional to horizontal were investigated. Borehole inclinations range from 0° to 90°, and all cases with inclinations less than 90° were considered conventional. All well models used an 8½-in. borehole through the reservoir. This borehole was cased or left open as required for the evaluation case. The conventional wells were modeled with standard, randomly-oriented perforations and with stress-oriented perforations for failure prevention.

Conventional well, standard perforation cases used perforations with 0.4-in. diameter, 11-in. formation penetration length, 6 spf density and 60-120° phasing. In these cases, no tie between perforation phase direction and wellbore stress direction was made. Conventional well, stress-oriented perforation cases used perforations with 0.4-in. diameter, 11-in. formation penetration length, 2-4 spf density and 0°/180° phasing (0° up, 180° down). Both horizontal and high-angle openhole well cases were evaluated for sand failure potential.


Conventional well cases were run for reservoir rocks with different sand strengths. UCS values of 3,242 psi and 1,152 psi are the lower average sand strength values and represent the formation failure analysis for Judy and Joanne sandstone reservoirs, respectively.

Conventional well, standard perforations. The finite element rock mechanics simulator solves for whether or not failure would occur for a given rock strength, pressure depletion and associated reservoir drawdown pressures. Results are displayed as a failure envelope, Fig. 5.

Fig. 5

Fig. 5. The finite element rock mechanics simulator solves for whether failure would occur for a given rock strength, pressure depletion and reservoir drawdown pressures.

The failure plot is made from individual runs, accounting for reservoir depletion and drawdown effects. The X-axis designates reservoir pressure, and the Y-axis designates flowing bottomhole pressure. A unit slope line runs diagonally across the plot, separating injection cases in the upper half of the plot from positive drawdown production cases in the lower half of the plot. A failure line is also shown.

In this example, the failure line intersects the unit slope line at about 2,500 psi. The drawdown failure line is for a particular rock strength, typically designated by the UCS value. The failure line represents the reservoir and producing pressure conditions, which resulted in formation failure for the rock UCS at the well and completion conditions. Pressure conditions above the failure line (green) are expected to allow sand-free production, while pressure conditions below the failure line (orange) are expected to result in formation failure and sand production.

Conventional well, oriented vs. non-oriented perforations. The range of sand failure prediction results, considering 715-4,026 psi UCS, for conventional wells completed with standard, non-oriented, perforations at 11,261-11,621-ft TVD are summarized in Fig. 6. The stronger rocks (above 4,026 psi UCS) could still fail, but failure would occur at much lower pressure when the reservoir is further depleting. This multi-rock plot contains a number of failure lines. Each represents a particular rock type, designated by its UCS. They all indicate that sand failure would happen early, i.e., within 16.4-22% or less of the reservoir depletion, if the conventional well is completed with standard (random) perforations. Field observation confirmed such early “solid production” results.

Fig. 6

Fig. 6. The range of sand failure prediction results, UCS 715-4,026 psi, for conventional wells completed with standard, non-oriented, perforations at 11,261-11,621 ft TVD.

Stress-oriented perforations in inclined wellbores produce a favorable effect on rock failure conditions in the Judy at 11,621 ft TVD, Fig. 7.

Fig. 7

Fig. 7. Formation failure analysis for the most representative Judy sandstone with UCS = 3,242 psi, using wellbore angles of 50°, 65°, 75°, and 80°.

The stability condition improvements from using stress-oriented perforations are significant. For example, for a 50° inclined well, the depletion failure (shear failure at drawdown pressure = 0 psi) could be delayed by 1,400 psi, if stress-oriented perforations were used instead of random ones. In the same manner, a delay of depletion-only sand failure is increased (improved) by 3,300 psi, 4,500 psi, and 5,100 psi for wells with 65°, 75°.and 80° hole inclinations, respectively.

However, there is also a significant limit for high drawdown in the Judy reservoir as the failure envelope is moving “upward” with positive slope in the fluid flow regime. This indicates that the perforation tunnels become unstable due to changing stress conditions. Similar failure envelopes were obtained for Joanne sands, but envelopes become a little more restraining in the drawdown portion. The Judy case is slightly better than Joanne’s, since the “slope” is milder, and it only becomes positive when hole angles increase to 65° or higher.

The upward failure envelopes in the fluid flow regime result from perforation tunnels becoming unstable. While applying drawdown to the oriented perforations, the degree of directional stress difference (Sv/Sh ratio) in the radial plane (tunnel cross-section) would become large and “inhomogeneous” due to the continuous fluid drawdown and large fluid flow. Therefore, if the rock itself or its cementation strength is not strong enough, the tunnel becomes weaker during the drawdown and pushes the curve upward, limiting the “sand-free” drawdown.

The stress ratio and perforation angle affect the overall stability of the perforation tunnel. The stability enhancement due to drawdown is most evident for stronger rocks and for a larger stress difference or Sv/Sh ratio. Other factors such as the rock non-linearity could also play a role in this special effect.

Openhole horizontal and high-angle wells. A similar failure analysis was conducted for both Judy and Joanne sandstone reservoirs. The objective was to quantify formation stability compared with other completion options. Results of the openhole horizontal and high-angle well failure modeling work are provided in a failure envelope. The hole angles analyzed are 90° (horizontal well) and 65°.


While our work on the Judy/Joanne reservoir formation failure analysis and sanding prediction was in progress, the new pre-Cretaceous well from the Judy platform, P20, was set for a March 2005 spud date. The Joanne sandstone’s relatively low UCS values and the fact the P20 was to be completed with an 80° wellbore deviation were sufficient to investigate downhole solids control solutions.

Two options were considered: standalone openhole screens and oriented perforations. Given the early results of our formation failure analysis and sanding prediction, and the success that ConocoPhillips UK Ltd had running screens in the southern North Sea since 1995, the use of screens was the preferred option. However, given that there had been no previous study work performed by the J Block to select an optimum drill-in fluid along with the long lead time on the base pipe required, this was not a viable option.

As an alternative, the Halliburton G-Force oriented-perforation system was chosen. The guns run were 3 1/8-in., 4 spf with 0°/180° phasing. This system was chosen based on our previous success in an Indonesian field, along with the ease of system deployment versus other perforation systems. The Well P20 completion was a 5½-in. monobore with a sliding-side-door/PBR/production packer/tailpipe assembly and a cemented production liner. Prior to running the upper completion, the guns were deployed on drill pipe in an overbalanced, clear caesium formate brine.

There were 1,200 ft of guns run across the Judy formation and 800 ft of guns run across the Joanne with about 600 ft of spacer between. On successful perforation, the upper completion was run using overbalanced clear fluid. With the completion landed and Christmas tree installed, the wellbore and annulus were circulated-out to inhibited seawater and the well was ready to be brought into production. The well was completed in September 2005.

As an evolution to the downhole solids control philosophy now being adopted on the Judy platform, studies are developing a standalone screen solution for the next Judy well (P21). The same upper completion will be run (minus the sliding side door). However, rather than using a cased production liner with oriented perforations, the operator hopes to complete it with 4-in. openhole sand screens.


When P20 was brought into production, its performance was above expectation with initial rates of 13,000 bopd and 33 MMcfd at 31% choke. For reservoir management reasons, the well continues to be operated on this choke setting. Solids production is monitored using a Cormon intrusive probe mounted on the P20 flowline.

Figure 8 shows the P20 failure envelope developed from the SAND3D modeling analysis. The green area shows the safe operating zone. The orange zone indicates that sand production is likely. The results of the operational envelope are summarized in the table below the chart and are compared with the standard TCP case.

Fig. 8

Fig. 8. Well P20’s failure envelope’s positive slope restricts drawdown to avoid early sand failure.

The “positive” slope of the failure line restricts drawdown so as not to induce early sand failure. The yellow dots are data points showing how the well was operated over a six-month period, since being brought online (through end March 2006). There were initial activity signs on the intrusive probe when P20 was started, which were attributed to wellbore cleaning. Since then, there has been no evidence of solids production. As can be seen from the two latest data points, we are producing solids free, despite venturing into the orange zone.


Embla Field is in PL018 license about 300 km southwest of Stavanger in the Norwegian North Sea. Over time, several field wells exhibited abnormally high production decline, and formation failure was considered a likely source. Pressure transient and production inflow revealed that perforation tunnel collapse could cause a pressure loss up to 99% of total drawdown.

Embla reservoirs are at ±13,250 ft TVDSS. The Devonian-age D1 and D3 sands are heterogeneous with thick, multilayered sand-shale sequences and up to 1,000 ft of hydrocarbon column. However, the Permian age sand is a high net-gross reservoir. These sands have 1-35 md and produce 42° API oil with 1.8-2.2 Mcf/bbl of gas. The zones have an average reservoir pressure of 12,200 psi and temperature of 325°F. Wells were drilled at shallow angles (up to 30°) and are completed conventionally with 6 or 12 spf, non-oriented perforations.


Three well cores from Wells 2/7-21S, 2/7-23S, and 2/7-26S were tested. Sand strengths varied from 1,800-7,000 psi UCS. Reservoir sands are generally strong and competent, with the majority ranging from 3,000-5,000 psi UCS. The sand strengths are relatively stronger because there are more fine-grained and tight rocks. With an HPHT well and a deep reservoir, there is good potential for sand failure, especially for sands with strengths below 3,500 psi UCS.

In the same manner as Judy/Joanne field, multiple plug samples were taken for triaxial tests, covering sand strength groups from 3,030-5,690 psi UCS. Unlike Joanne sands’ cap failure, only shear failure mode developed for Embla sands, due to its lower 12% average porosity.

The stress gradients for the Embla reservoirs are derived and estimated at: 1.02 psi/ft Sv; 0.95 psi/ft Shmax; and 0.91 psi/ft Shmin.

A range of well geometries from conventional to horizontal were investigated along with perforations. All models used an 8½-in. borehole through the reservoir. Failure lines show that rocks with 1,800 psi UCS should have shear failure when the reservoir pressure drops from Pri = 12,191 psi to 7,491 psi (38.6% pressure depletion). Beyond this, sand production occurs for all drawdown conditions and field observations agree. Embla sands with an average 3,455 psi UCS were more stable than the lowest UCS 1,800 psi rocks. Depletion-only failure can initiate when the reservoir pressure drops to 6,091 psi (50.0% pressure depletion).

Stress-oriented perforations in inclined wellbores also produce a favorable effect on Embla rock failure conditions, i.e., the higher hole inclination the better. All failure lines show a “negative” slope. The Embla sandstone is fundamentally stronger than Judy/Joanne. Therefore, Embla drawdown is not as restricted as for Judy/Joanne reservoirs.

Sand failures are independent of well inclination angle with random or arbitrary perforations. A significant percentage of random perfs are incorrectly aligned. However, the majority of randomly-perfed tunnels would fail above 40-50% depletion.

Modeling indicates that top/bottom-oriented perforations could delay sand failure, especially at wellbore inclinations above 40°. When hole inclination reaches 70-75°, there would be little or no sand failure, even if reservoir pressure was fully depleted. This is due in large part because, at higher well angles, oriented up/down perfs align somewhat parallel to the maximum stress direction. At 60-75° hole angles, oriented top/bottom perforations offer a significant increase of “allowable” reservoir pressure depletion in the weakest rock.


Rocks with a reference UCS of 1,800 psi and 3,455 psi are all likely to produce sand at some point. As expected, an increase in hole angle induces sand failure sooner during the well’s productive life. Likewise, the stronger reservoir rocks would see sand failures at much later stage.

For a higher 3,455 psi UCS in the same horizontal openhole completion, sand production could start when the reservoir pressure is depleted by 5,500 psi (45.1% original pressure); this is a 10.6% improvement in drainable reservoir pressure without initiating sand failure.

In wells with an openhole inclination angle at 60° and 50°, pressure depletion by 41.0% and 46.0%, respectively, could cause sand failure in the low-strength portion of the Embla reservoir (1,800 psi UCS).


The use of stand-alone screens was considered as a completion option in an openhole high-angle or horizontal Embla well. We assumed that a 5.62-7.66-in. OD screen could be used for the 8½-in. open hole.

The larger diameter minimized flow plugging and screen collapse problems. However, we assumed it would be installed in a highly inclined well, so we select a 6.13-in. OD screen that left a 1-in. clearance between the outer shroud and borehole annulus. Numerical analysis indicated that an openhole completion could induce sand failures in the weakest sand interval at well inclinations as low as 30°.

The results of Pipe3D analysis show that standard N-80 or J-55 base pipe would remain stable at abandonment reservoir pressure as low as 500 psi. It is safe to use the commercially available stand-alone screens for Embla, regardless of angle.

The issue of formation permeability is a critical factor in determining the effectiveness of a stand-alone screen. If the formation permeability is less than 100 md like the most Embla reservoirs, then the skin damage per openhole foot is very small.


Based on the sand failure study, cost evaluation and completion design parameters, engineers decided that the newest Embla well would penetrate the reservoir with a 60° wellbore and be complete with a cased hole and stress-oriented perforations. The well angle through the reservoir was later revised to 50-55° because of HPHT challenges and logging tool limits.

Well 2/7-D-07’s construction program was designed to achieve the 50-55° well angle. The well was turned to the ±50° deviation at about 12,000-ft TVD and held there to 15,196-ft TVD. Wireline conveyed the 3 3/8-in. OD eccentrically-weighted perforating guns to orient the charges at 0°/180°. The guns were loaded at 6 spf with deep-penetrating charges.

Drilling and completion went smoothly and Well 2/7-D-07 reported no major problems. The initial completion included 426 ft of the pay section and 10 perforating runs were required. The gun system included a shot orientation detection device to record the gun’s orientation at detonation time and data indicated the orientation system was functional.

The well was placed on production in December 2005. Based on the limited production to date, it is still too early in the well life cycle to determine the success of the stress-oriented perforation completion strategy.


Our approach to the well construction and completion design uses a systematic reservoir formation failure, sanding prediction and screen failure analysis, based on our North Sea operational cases.

Reservoir rock strength and failure behaviors are key elements to determine well performance, completion scheme selection and effective sand control during reservoir depletion. The clear difference in sand failure mechanism between the Judy/Joanne and Embla reservoirs governed the choice of completion design. The effectiveness of the stress-oriented completion technique in high-angle wells is good for many different rock types, but may not be ideal for others where control of sand failure or production becomes difficult or restrictive during reservoir production and depletion.

The use of a systematic SAND3D/Pipe3D analysis offers a realistic and reliable approach to evaluating and optimizing well completion design options, when sand production and wellbore or perforation collapse are considered or evaluated as a risk. Field experience supports this.

Periodically taking reservoir cores is a worthwhile investment for future design of a well’s construction and completion scheme to achieve optimum well productivity with effective sand control or management and prolonged well life. WO


The authors thank ConocoPhillips’ management and its North Sea unit partners Total, ENI, Norsk Hydro, Statoil and Petoro for Embla (under License PL018), as well as British Gas and ENI for Judy/Joanne, for permission to publish. We appreciate the review and constructive suggestions by many colleagues, particularly Hilde Alexandersen and Craig Stewart. This article was prepared from SPE103244 presented at the 2006 SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, September 24-27, 2006.


1  Morita, N., et al, “Realistic sand-production prediction: Numerical approach,” SPE Production Engineering Journal, v. 40, n. 9, p 15-24, February 1989.
2  Morita, N., et al, “Parametric study of sand production prediction: Analytical approach,” SPE Production Engineering Journal, v. 5, n. 1, pp. 25-33, February 1989.
3  Morita, N. and G. F. Fuh, “Prediction of sand problems of a horizontal well from sand production histories of perforated cased wells,” SPE 48975, presented at SPE Annual Technical Conference and Exhibition, New Orleans, La., September 27-30, 1998
4  Burton, R. C., et al, “Application of reservoir strength characterization and formation failure modeling to analyze sand production potential and formulate sand control strategies for a series of North Sea reservoirs,” SPE 48979, presented at SPE Annual Technical Conference and Exhibition, New Orleans, La., September 27-30, 1998.
5  Fuh, G. F., et al, “Pre-Cretaceous Judy/Joanne reservoir formation failure analysis for sanding prediction and well completion design,” ConocoPhillips Report, WBT.550077.PO, 2005.
6  Fuh, G. F., et al, “Embla reservoir formation failure analysis for sanding evaluation and screen stability study,” ConocoPhillips Report, WBT.520148.PO, 2005.
7  Fuh, G. F. and N. Morita, “Development of Pipe3D model for casing and/or screen stability analysis of sequential loading during reservoir depletion and drawdown,” ConocoPhillips Report, WBT.CU5711.PO., 2004.
8  Morita, N., et al, “Collapse resistance of tubular strings under geotectonic load,” SPE 95691, SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 9-12, 2005
9 Bruno, M. S., “Geomechanical analysis and decision analysis for mitigating compaction related casing damage,” SPE 71695, SPE Annual Technical Conference & Exhibition, New Orleans, La., September 30- October 3, 2001.



Giin-Fa Fuh earned a PhD degree in rock mechanics from the University of Wisconsin-Madison. He has 29 years’ experience with ConocoPhillips providing engineering services and technology development to the company’s worldwide business units. His projects concern drilling and completion-related wellbore stability, formation failure/sanding prediction, wellbore strengthening and lost circulation prevention, reservoir compaction and subsidence prediction, and formation fracturing. Dr. Fuh is a ConocoPhillips engineering fellow in Upstream Technology, Houston, Texas.


Ian Ramshaw earned a BS degree in chemical engineering from Cambridge University. He began his career as a service company field engineer and has been with ConocoPhillips since 2001 working in various roles. Ramshaw is the ConocoPhillips’ North Sea J-Block asset production team leader, based in Aberdeen.


Kerry Freedman earned a BS degree in petroleum engineering from Louisiana State University. He is a staff production/completions engineer for ConocoPhillips’ North Sea business unit.


Nabeel Abdelmalek earned a BS degree in chemistry and an MS degree in petroleum engineering from the University of Pittsburgh. He has 30 years’ experience in engineering with ConocoPhillips, providing integrated technical support for field developments around the world, well design, performance analysis and field production optimization. Abdelmalek has specific interests in reservoir, production and well completion engineering.


Nobuo Morita earned MS and PhD degrees in petroleum engineering from the University of Texas at Austin. Dr. Morita was a research fellow for Conoco and is now a professor at Waseda University, Japan, in the Resources and Environmental Engineering department.


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