Avoiding the sand trap
  from: Offshore Engineer
  by: Colin McPhee
  Monday, April 07, 2008

Some 70% of the world’s oil and gas reserves are contained in sandstone reservoirs where sand is likely to become a problem at some point during the life of the field. Senergy’s Colin McPhee discusses the issues and challenges for operators worldwide and the effectiveness of current sand management methods and technologies.

Sand production creates many significant challenges in field and facilities management. If sand is lifted to surface, the high impact momentum and abrasiveness of sand particles can lead to erosion of chokes, valves and pipeline components and can threaten well and surface facilities integrity, with safety being the dominant issue. Other issues include regular shutdowns to clean out separators and high HSE driven removal costs. In lower velocity regimes, sand may not be lifted to surface but can settle downhole where it can fill the production tubing and eventually choke the well.

Sand production issues arise:

• at the reservoir appraisal stage: where the risk of sand production must be quantified to formulate the reservoir management philosophy, cost the completion strategy, prepare an appropriate front end engineering design (FEED), and to satisfy regulatory authorities; and
• during production operations: where sand production has been encountered and must be economically managed, taking into account existing facilities and future well completions.

There are two main enabling mechanisms for sand production. First, the rock must fail, and there must be sufficient fluid flow to transport the failed sand into the wellbore and thence to surface.

Shear failure occurs when the effective tangential stresses acting on the well or perforation exceed the shear strength of the formation. Failure can occur on or soon after production startup if the drawdowns are too high or later in the field life as the reservoir pressure reduces on depletion. The material in the failure zone undergoes yield and deforms plastically. If the plasticised material is unable to sustain any tensile stress, flow-induced drag forces can pull the sand grains apart and into the well. If well inflow conditions cause the failed zone to grow outward, the damage will be compounded and prolonged and continuous solids production can result. However, sand production can be self-stabilizing: a stable sand arch can form around a perforation cavity and the fluid velocities will reduce as the cavity expands.

Sand control

Historically, the principal means of controlling or mitigating against sand production has been either to limit flow to a maximum sand-free rate (MSFR) or to install some form of sand exclusion into the well completion. Attempts to consolidate the failed sand by egluingf the grains together have proven largely unsuccessful, so most sand control completions include some form of downhole sand filter. Various techniques have been successfully developed and applied:

• standalone screens (wire wrapped, prepacked, premium);
• compliant/expandable screens;
• gravel packing (cased hole and open hole);
• frac pack; and
• high rate water pack (HRWP).

These systems are designed to trap and retain sand particles but to allow fines particles to be produced so that they donft block or plug the filters. If successful, many of the issues associated with sand production downhole and at surface are avoided. Even where there is no immediate sanding problem, sand exclusion completions are sometimes installed as an einsurance policyf to deal with potential future sand production . This approach assumes that a sand exclusion system can be implemented with little risk, be reliable over the field lifetime, and meet the reservoir, well and facilities objectives.

Recognising the problems associated with sand control reliability and performance, over the last 10 years the industry has increasingly focused on the alternative of allowing a degree of sand production and managing it. This involves the development and monitoring of optimal sand control strategies that recognize the particular problems and constraints of the field development, yet maximize productivity and completion longevity. Sand management can be conducted throughout the productive lifetime of the field, whereas sand exclusion cannot be guaranteed to perform adequately over the same period.

Sand management principles

Challenging convention in sand control has both cost and productivity benefits. Effective sand management can be achieved by applying holistic sand management principles that address:

• identifying and quantifying the potential for sand production over field life in individual wells using coupled geomechanics and sand failure models;
• understanding potential sand control completion skins and completion longevity;
• assessing sand transport and upper completion and topsides erosion risks;
• seeking alternatives to downhole sand exclusion; and
• embedding sand management in the asset management process.

This demands an integrated, multi-disciplinary approach that confronts the intellectual compartmentalization inherent in some operating companies by drawing on the skills of geologists, petrophysicists, reservoir and production engineers, and facilities engineers.

Effective sand management requires the development of a field-validated methodology to predict the critical conditions for sand production. Geomechanics provides key data inputs: viz rock strength profiles and mechanical behaviour, and in situ stress magnitude and orientation.

The various approaches that are used in the industry to predict sand failure range from simple empiricism (eg a sonic velocity cut-off) through lab simulations and analytical calculations to numerical simulators. Recent developments include quantification of how much sand will be produced under different downhole conditions and flow regimes. However, more complex modeling often requires data which are neither accurate nor readily available, hence the results from such models are not necessarily more reliable than those from simpler approaches which require more easily accessible input data. A pragmatic approach . which delivers answers in a petroleum engineering context and recognises the uncertainties in both input and model calibration data . is essential.

It is important to understand and benchmark the performance of sand control completions to factor into well productivity assessments and to better quantify the risk of failure. Table 1 lists P90, P50 and P10 mechanical skin factors from sand control completions in the UK Southern North Sea.

Productivity impairment (and skin) commonly arises from: poor cleanup following installation; incorrectly sized screen openings or gravel pack sizing leading to fines material blocking the screen or gravel; or the unsupported formation collapsing around the screen resulting in a low permeability pack. Careful consideration of the potential for sanding, particle size data and well operating conditions is required to determine the optimum sand face completion technique. In the case of gas wells rate dependent, non-Darcy skin arising from high gas velocities through the filtering medium will also impact well productivity.

Sand control completions can also be unreliable. The King et al database of sand control completion failures (see referemces) is readily available but needs to be carefully interpreted. As sand production in some fields is more closely linked to depletion, deferring the installation of sand control might limit the risk of completion failure before it is actually required to control sand.

All relevant information must be included in the decision making process rather than the apocryphal ewell it worked in the Gulf of Mexico so itfll work here!f For example, Farrow et al present a screening methodology that evaluates and ranks the available sand control techniques in a systematic manner, allowing a consistent, balanced and transparent view of benefits and risks across the different esystemf aspects.

Sand transport and erosion models

Sand transport models are available to compute sand deposition as a function of time and fluid solids suspension capacity. This allows an estimate of the sand loading rate at surface in high rate wells and whether sand will be lifted in low rate wells. In the worst case the well could become plugged with sand while, at surface, there may be limited indications that the well even has a problem.

Another crucial sand management tool, erosion modelling, provides an accurate measure of the time it would take a given material to erode for a particular fluid rate and sand loading. The eindustry standardf API RP 14E (API-14) erosion model was developed for fluid flow and does not account for solids and the impact of different fluid impact angles. Newer approaches , which do, suggest that the API model is too optimistic at low liquid rates while it is conservative at high liquid rates.

The conventional view is that any sand production in gas wells is largely unacceptable, principally because of the high velocities associated with gas production. However, erosion management methodologies have been developed that link well sand risk ranking, identification of erosion critical components, and detailed erosion assessment using 3D computer modelling tools. This has enabled the development of a emaximum acceptable sand ratef (MASR) criterion rather than the ultra-conservative MSFR that limits production in many fields.

Alternatives to sand control

Some of the following techniques have seen increasing application in managing produced sand in the absence of downhole sand control.

• Oriented perforating involves shooting perforations in the direction of maximum stress to minimise the tangential stresses acting on the perforation tunnels. Figure 1 plots the sand free operating envelope for a 56‹ deviated well completed in a relatively weak formation (TWC strength 2000psi) in a normal stress regime where the maximum stress is vertical. Critical BHFPs are plotted for perforations oriented from 0‹ to 90‹ to top dead centre of the casing. Where the BHFP and reservoir pressure for any well flowing condition cross the appropriate rock strength curve sand failure is predicted. Orienting perforations within }30‹ to the top of the deviated well will prevent perforation failure over field life (500psi abandonment pressure). Successful applications have been reported in Norway, UKCS and elsewhere, but it is more expensive than other sand control completions and it does require an accurate knowledge of the stress regime, and the alteration in the stress field caused by depletion.
• Selective perforating avoids perforating the weaker and sand prone intervals. In a gas field in Pakistan, it has delivered well rates in excess of 100mmscf/d with sand production significantly below tolerable limits, and substantial cost savings and reduced completion failure risks compared to conventional cased-hole sand exclusion completions. Its success relies on there being sufficient formation permeability to allow hydrocarbon to flow from the high quality, weaker sands to the lower quality, perforated, stronger sands; an accurate knowledge of the rock strength profile in the target intervals from core-calibrated wireline logs; and detailed inflow performance modelling to ensure that the increase in drawdown in the stronger intervals does not exceed the critical values for sand production.
• Well conditioning. The well is conditioned by deliberately inducing sand production from around a perforation tunnel using high drawdowns, then beaning down to a lower rate. The method relies on the formation of stable arch in weak or failed sand around the perforation tunnel. Although, the arch can be destabilised by over-rapid bean-up or by water production, the technique provides a potentially powerful way of retarding sand production in favourable conditions, especially in the early stages of reservoir depletion. An average productivity gain of 44% in conditioned wells has been reported for a Norwegian field primarily from increased well PI (through removal of near wellbore formation damage) and increased sand free rates.
• Living with sand to surface. Statoilfs adoption of a sand management strategy for Statfjord and Gullfaks has been crucial for prolonging economic reservoir development during tail production. By choosing to deal with sand topsides, the operator has been able to complete low cost wells completed without sand control equipment and has made significant gains in production. Nevertheless, living with sand production presents several major challenges . notably the ability to install sand separation and treatment equipment on the well platform. This can be difficult or impossible to retrofit on existing platforms. Both incremental capex (to construct new, or upgrade to, sand capable platforms) and opex costs (to deal with periodic well entries, eroded component replacement, additional shutdowns/ maintenance, sand disposal issues, and safety) must be carefully considered in the light of other alternatives.

Summary

The last decade has seen significant advances in the understanding of sand production mechanisms and their controlling factors, and in modelling and monitoring sand transport and erosion. These have allowed the development of integrated sand management strategies which employ one or several of the above options to control sand to a tolerable level whilst maintaining productivity. The advantages over a sand exclusion strategy are lower up front completion costs, avoidance of risky and potentially damaging completion operations, retention of wellbore ID for future intervention, and potentially higher production rates. These advantages must be balanced by increased costs required to upgrade facilities, for component replacement, for additional well intervention, enhanced field data acquisition (eg sand monitoring equipment), and for increased engineering (dedicated surveillance and analysis) and planning resources.

Historically, intellectual compartmentalisation at the field, engineering and management levels within many companies has resulted in missed sand management opportunities. Appointing a sand management champion for the asset with clear ownership of sand management data, improving communication between offshore operations and onshore asset management, tuning and revising operational procedures and practices in the event of sand production, and moving from MSFR to MASR, can yield significant benefits in both productivity and costs.

In the end the choice between sand control and sand management should not be seen as a doctrinal issue, and each approach should be carefully evaluated and costed in light of the production and reservoir management objectives as well as completion and facilities constraints. OE

Click here to register to receive your own copy of Offshore Engineer each month.