Chapter 5. Engineered Controls
Chapter Contents
Every variable from pressure, temperature, fluid type, and well depth to logistics and metocean conditions requires control; an uncontrolled variable represents risk to the successful outcome of the well test. A control is a physical barrier, a device or a process that acts to constrain or direct the effects of a variable. There are only two types, engineered and procedural controls, and collectively they make up the well test design. Once in place, engineered controls physically eliminate or contain hazards associated with a particular variable. They do not require human intervention to be effective and are therefore more reliable than procedural controls. The purpose of this chapter is to describe common well test engineering controls and the processes behind their selection.
The order in which topics are presented here does not necessarily follow the order in which issues would be tackled and resolved during planning. Instead the order follows a learning progression, and information in the first section is used and referenced in later sections.
- Fluids
- Materials
- Erosion
- Pipework Sizing
- Nodal Analysis
- Tubing Stress Analysis
- Hazard and Operability
- Rig Interface Engineering
- Facility Design and Engineering Report
- Design Review
Fluids
Fluids are used primarily to control well pressure, but they also perform a number of other tasks depending on the operation. The type of fluid also varies according to the operation. When drilling, mud provides a pressure barrier to the reservoir, carries cuttings clear of the drill bit and back to surface, and maintains borehole stability. It also transmits logging while drilling LWD signals and drives downhole motors for directional drilling. Drilling mud contains various ingredients to perform these tasks, bridging agents help to stop fluid loss into the formation, dissolved solids adjust the weight of the fluid, and thickeners adjust viscosity and provide mechanical strength to help support the wellbore. During the drilling operation, this mud is in constant motion, travelling down the drill string and up the annular space outside the drill string back to the rig where it is filtered and conditioned for reuse.
In a well test, fluid in the annulus, between the test string and the production casing, is static for the entire period of the test. It undergoes pressure cycling as annulus-operated tools are opened and closed, and it is subject to changes in temperature, heating during production, and cooling during shut-in or when pumping fluids into the test string. Drilling mud, whether water or oil based, is not intended for this application. Under static conditions, there is a potential for dissolved barite solids to come out of solution, and if static for extended periods or at elevated temperatures. This solids dropout can become severe to the point that they compact above the packer and in tool operating mechanisms. The consequences may include inability to operate downhole tools and may result in premature termination of the well test. Solids dropout might also result with difficulties in retrieving some packers due to compaction above the elements. Drilling mud is compressible and therefore not ideally suited for transmitting pressure signals over the length of the well to downhole tools, many of which require multiple and sometimes precise pressure signals in order to cycle correctly. These problems vary according to prevailing conditions. As mud weight increases to achieve greater hydrostatic pressures for well control purposes, the solids content in the mud also increases and results in potentially greater volumes of solids dropout. As the well temperature increases, the problems associated with changes in mud properties become more pronounced.
Brine provides an alternative fluid for testing applications. Brine is basically water with dissolved salt to provide the desired weight. Brine has certain advantages for well test applications: it is stable even at high temperatures, and it is practically incompressible and therefore suited for transmitting annulus pressure signals to downhole tools.
Unfortunately, brine is entirely unsuited to drilling because it has none of the bridging agents that help prevent fluid loss to the formation. Nor does brine contribute to wellbore stability, with the result that for many well tests, the drilling mud system must be changed to a brine test fluid. The disadvantages include the cost of a second fluid system, the cost associated with the time needed to change out the fluids, the resources required to manage the logistics at the well site or shore base facility on the supply vessels and at the rig, together with the resources required to clean pit systems and supply vessel storage tanks to avoid contamination. All of these must be coordinated so that the well is ready to receive the change-out in fluids without compromising well barriers or formation damage and with minimal impact on critical path time. A decision to use brine as a test fluid is a significant one and is assessed on a case-by-case basis, sometimes directed by company policy, by the logistics involved, or by well conditions.
Underbalance
Underbalance fluids facilitate the controlled production of reservoir fluid to surface. An underbalance pressure is created when heavy kill weight fluid in the tubing, mud, or brine is displaced with a lighter underbalance fluid, sometimes referred to as cushion fluid. The underbalance pressure is the differential measured at surface between the hydrostatic weight of the well fluid and the pressure in the reservoir. The magnitude of the underbalance pressure is varied by altering the amount of fluid displaced and selecting the type of underbalance fluid.
Selecting the optimum underbalance pressure is a decision that must involve the subsurface team, considering the conditions of skin, fluid loss to the formation, permeability, and the potential for sand production. An inadequate underbalance may fail to overcome the resistance to flow presented by skin effects and fluid losses. Skin is a layer of low permeability in the near wellbore area caused by the drilling process. Drilling can damage the formation face, while drilling mud penetrates the formation rock to varying degrees. Solids in the mud act as bridging agents that become embedded in the rock pores producing a low permeability skin at the formation face (see Figure 2.1). Other than the effect of skin, drilling mud may have penetrated some distance into the formation. This fluid loss to the formation can be significant and may vary from tens to thousands of barrels. When attempting to flow the well later, much of this heavy fluid may produce back into the wellbore, along with, or instead of, reservoir hydrocarbons. In some instances, enough heavy fluid may be produced in the wellbore to stop production, and in such cases it may be necessary to repeat the underbalance operation in order to recover enough drilling fluid to allow the reservoir fluids to produce.
Excessive underbalance may result in formation damage, including failure of the sand face, which can lead to sand production. An unconsolidated formation is one in which the particles that make up the rock material are loosely bound to one another and can, given the right conditions, separate from the formation as sand. The subsurface team evaluates formation rock strength data from cores and logs in order to determine the likelihood for this to occur. Lab testing of cores is often performed to simulate production conditions to better assess the initial conditions. If the reservoir pressure is at or near the fluid bubble point pressure (i.e. the pressure at and below which solution gas separates from oil), this may result with higher than expected gas production and could affect the way the drawdown develops.
Figure 5.1. Underbalance pressure
Diesel, oil base mud, and nitrogen are common underbalance fluids. The selection of the fluid has consequences for the design of the test other than its effect on the reservoir. These fluids may require specialized services and handling procedures for pumping or disposal. Diesel is a common choice. With a low specific gravity, it can provide a wide range of underbalance pressures, depending on the volume displaced to the test string. It is conveniently available on every drilling facility and does not require additional contractor services. The cement unit also available at all drilling facilities can readily deliver diesel to the test string, and because it is flammable, diesel is easy to dispose of at the flare.
With the example illustrated in Figure 5.2, a diesel cushion is displaced to a depth of 2,700 m, just above the circulating valve. The underbalance provided can be calculated as shown.
Figure 5.2. Underbalance pressure example
In some parts of the world where regulations restrict the use of diesel or prohibit flaring, alternative fluids must be used. Nitrogen gas offers an alternative capable of greater underbalance pressures and is environmentally friendly. Nitrogen is transported as a liquid and pumped as a gas. The handling procedures differ significantly from diesel, and a dedicated nitrogen service contractor is required to supply personnel and equipment, including liquid nitrogen tanks, a converter/pump unit, and workshop. All of this entails additional cost, handling, and deck space. (Refer to Figure 2.18 for a nitrogen system setup.)
The calculation for the hydrostatic pressure exerted by the nitrogen column is complicated by the fact that nitrogen is compressible and therefore does not keep a linear pressure gradient. A precise calculation can be obtained using tables and formulas available from the nitrogen service contractor.
Materials
The materials and the equipment assemblies provided by contractors and suppliers are delivered with specifications that detail design limitations — for example, yield strength, load capacity, safe working pressure, and safe operating temperature range. For new or recently surveyed materials and equipment, it may be reasonable to expect that it will perform to specifications. In many instances, however, operating materials and equipment at or near its maximum safe design limits is not always advisable. To take an example, consider a test separator. Perhaps as many as four years since its last major survey, in the intervening period, this separator will have performed a number of well test operations, travelling to and from different well sites and exposed to a range of well test environments. After each operation, the contractor will have performed routine service work to maintain the equipment. However, contractor processes are fallible, as are the service personnel following those processes. Despite detailed procedures, maintenance systems audits, and equipment inspections, details are often overlooked. To illustrate, suppose the wrong seal material is used during assembly of one of the separator valves. It is likely that the seal would hold pressure during the normal workshop and well site hydro test, but may subsequently fail in operation at high temperature. This is not to say that equipment supplied by contractors should be considered unreliable, but any equipment such as a separator rated to operate at certain conditions will reliably perform only at these conditions, provided every single component (i.e., valves, seals, flanges, instrumentation, pipework, and the vessel itself) is fully serviced according to the manufacturer's and contractors procedures. In a perfect world, it would be maintained fully in accordance with the manufacturing specifications. In practice, this may not be the case, and it is a reasonable precaution when selecting materials and equipment to suit a particular set of environmental conditions that some margin of safety is built into the selection so that it will not be operating at or near design limits. The same is no less true for the materials and equipment supplied by the facility owner, rig-supplied pipework, deck spaces, and so on. The facility specifications are discussed in the Rig Engineering Interfaces section of this chapter.
Elastomers
Elastomers are widely used for seal and gasket materials; contractors assemble equipment using different elastomers suited to the conditions defined in the Basis for Design. A range of synthetic polymers are produced by contractors and suppliers of elastomers to make o-rings, packer elements, pipe seals, valve seals, gaskets, and hose material. Each has properties that suit it to a particular set of conditions. Some of those properties include resistance to chemical deterioration through contact with petroleum, hydrogen sulphide, carbon dioxide, and other fluids. Other properties include abrasion resistance, explosive decompression resistance, and a low friction coefficient required for dynamic seals.
For high-pressure applications, hard material seals have better anti-extrusion properties, but with high temperatures some seals soften and become more prone to extrusion, so material selection needs to consider how the anti-extrusion resistance changes with temperature.
Generic synthetic polymers include Nitrile (NBR), Hydrogenated Nitrile (HNBR), Flouroelastomers (FKM), Tetrafluoroethylene Propylene (FEPM), and Perfluoroelastomers (FFKM). Manufacturers develop variants of these to produce polymers with specific properties for specialized applications. Such formulations have their own proprietary names.
The well test engineer provides details of the expected fluids and conditions in the Basis for Design document. Using this document, contractors select appropriate elastomers for the equipment within their scope of supply. Technical documentation provided by the contractor as part of their package preparation includes elastomer type and specifications. Elastomer selection for well tests involving extreme or hostile conditions requires close scrutiny and may require input from materials specialists and, in some cases, lab testing.
Metal Alloys
Surfaces exposed to the well fluid environment and in particular flow-wetted surfaces (i.e., those surfaces in contact with producing fluids) may suffer rapid corrosion deterioration through chemical attack or erosion through mechanical wear. A corrosion-resistant alloy (CRA) is a material that resists these effects and can be used in casing, tubing, downhole tools, surface pipework, manifolds, valves, and flanges. With increasingly hostile well environments, use of more exotic and expensive CRAs is necessary. In a more benign environment, the exposure time for materials used in a well test is short compared to a production environment. For this reason the more exotic alloys are generally not required. However, in more hostile conditions at extremes of temperature or high concentrations of carbon dioxide or H2S, material suitability must be assessed when selecting equipment for the test because of the risk of corrosion failure, also called environmentally assisted cracking (EAC). EAC refers to a number of corrosion processes that share specific characteristics and that can occur during a well test. Corrosion occurs rapidly in materials exposed to the right environmental conditions and results in metal embrittlement. Sulphide and chloride stress cracking are examples of environmentally assisted cracking that can occur during the well test.
Sulphide stress cracking (SSC) is a form of corrosion that attacks metals under stress. When present with water, a reaction takes place that forms cracks and hardening of the material, rendering the metal susceptible to failure. This effect of the chemical reaction is metal embrittlement or hardening. Higher strength materials are at greater risk to sulphide stress cracking due to the higher internal stresses within the material.
The common materials reference standard NACE MR-01-75 identifies a number of factors that contribute to the corrosion of carbon and low-alloy steels in H2S environments; among them are the following.
- Chemical composition, method of manufacture, strength, hardness, amount of cold work, and heat treatment condition
- Hydrogen sulphide concentration
- Acidity or pH of the water phase
- Presence of sulphur or other oxidants
- Tensile stress
- Temperatures
- Exposure duration
Because softer metals are more resistant to SSC, hardness is often used as a measure of SSC resistance. Chloride stress cracking, like sulphide stress cracking, occurs on tubing under tensile stress and affects steels in a similar manner, resulting in metal embrittlement. Chlorides can be present at high concentrations in drilling fluids and formation water.
Hydrogen Sulphide Concentrations
Hydrogen sulphide is measured in parts per million. Low concentrations at low pressures present an insignificant threat of damage to equipment, but as concentrations increase and as gas pressure increases, the effects of H2S present in the gas become significant. This partial pressure exerted by the H2S component of the gas is an important feature for material selection. The reference standard NACE MR-01-75 designated H2S or sour service environment as a petroleum gas phase, with an H2S partial pressure of greater than 0.05 psia and a total pressure greater than 65 psia or an H2S concentration greater than 150,000 ppm.
In a well test environment where there are uncertainties regarding fluid makeup, it is not practical to design a system to remove chlorides or hydrogen sulphide before it passes through process equipment. Instead, materials are selected on the basis of their resistance to failure in the presence of these corrosive agents under flowing conditions.
It is not possible to predict the exact nature of the fluids to which well test equipment will be exposed, even if exposure periods are short compared with production equipment. Well test equipment is used in uncertain and varying environments, with the result that most well test equipment is manufactured with H2S corrosion resistant materials as standard. When planning a well test for a known sour environment, the well test engineer must include controls to ensure that all materials with a potential exposure to production fluids are in accordance with the materials standards. Such controls exist in the equipment certification inspections and the design verification process.
Erosion
Pipework and equipment erosion can occur during well test activity and may result in leaks that have the potential to escalate into fire and explosion events.
Four general mechanisms can contribute to erosion.
- Particulate erosion
- Liquid droplet erosion
- Erosion-corrosion
- Cavitation
The conditions giving rise to these erosion mechanisms are dependent on flowing conditions in particular fluid velocity and the fluid medium, liquid or gas. In a well test setup, these conditions are most severe at chokes, elbows, check valves, throttling valves, flow restrictors, and pipe reducers. Since most pipework and valve materials are manufactured from carbon steel, except for some components where greater resistance to erosion is essential, controls are necessary to manage erosion hazards. Choke inserts are generally manufactured from tungsten carbide and some throttling valve internals of stainless steel. These materials have greater resistance to erosion but still frequently experience erosion damage under the right conditions.
The most common and generally the most serious form of erosion occurs when solid particles such as sand, suspended in rapidly moving gas, impinge onto pipework surfaces, causing pits and cratering that reduce the wall thickness of the pipe. The angle at which the particles impinge on the surface significantly influences the effect. Direct impingement is less severe than high angles; very little particulate erosion occurs in straight pipe where the flow is essentially parallel to the inner pipe surface. As a result, erosion occurs at elbows and reducers more so than in straight pipes or tee junctions, where the solid particles strike the pipe walls at angles.
The likelihood for sand production is at its highest during the initial cleanup and after choke changes. Gas well tests present the greatest risk because the velocities inside the pipework are high and because solid particles are not carried with the gas around bends or turns within the flow stream but instead, owing to their greater mass and the low viscosity of gas, tend to travel in straight lines through the gas and impinge on internal pipe surfaces. Slugging can have the same effect as choke changes. Sand can accumulate at low points during stable flow but produce in greater quantities and at the higher velocities if flow slugging occurs (i.e., periodic and unpredictable production at higher than expected rates).
Small solid particles <10 microns carried with the produced fluid contribute little to particulate erosion. Very large solid particles >1 mm are slower moving and tend to settle at low points and also contribute little to erosion. However, their accumulation may cause other production problems if produced in sufficient volumes. Particles in the size range 50–100 microns represent a typical size distribution in unconsolidated sand. Their abrasiveness, or ability to cause erosion, is dependent not only on their size and velocity but also on their hardness and shape, sharp-edged particles being more abrasive.
Although the relative material softness in elastomers will absorb some of the impact energy, elastomers used in pipe and valve seals are often very susceptible to erosion by the same mechanisms as steel pipe. The other erosion mechanisms listed at the start of this section contribute less to erosion during well test activity. Brief descriptions of these mechanisms are included in the glossary.
Solids control depends to a large extent on the degree of understanding of the subsurface team as to the nature of the solids and the likelihood for solids production. Without some guidance on size distribution and quantity, it can be difficult to design effective controls. Studies based on core data provide information on likely solids production and on the particle geometry and size distribution. Offset data and experience from similar operations also provide valuable data.
It is the task of the well test engineer and the planning team to develop an erosion management plan that will include a combination of some or all of the following controls.
- Pipework design, sizing, and velocity control
- Sand screens, filters, and sand separators
- Sand and erosion monitoring
Pipe-sizing calculations use inputs provided from tools such as nodal analysis to show the relationship between production rate and fluid velocities and pressures for a range of different pipe sizes. The program may be written so as to avoid production rates where erosion velocities occur or to limit the flow duration at these rates and thereby reduce the erosion risk. Where the test objectives mandate high production rates, large-bore pipes may be utilized to reduce the fluid velocity, thus providing an engineered solution to the problem.
Physically filtering sand downhole or at surface is also possible. Downhole screens (Figure 5.3) are in essence perforated tubing joints wrapped with wire and form a mesh to provide a filter, sized to suit the expected solids.
Figure 5.3. Sand screen
In the case of severe sand production, more sophisticated downhole sand exclusion is required.
A gravel pack (see Figure 5.4) entails packing off the wellbore area using specially sized gravel beads, which provide wellbore support as well as solids filtration. Such systems require considerable planning lead time.
Figure 5.4. Gravel pack
Surface-located sand filtration equipment has the advantage of being readily accessible for inspection, sampling, and sand removal, but does not prevent the inflow of sand downhole, which may cause production problems within the well. Sand filters situated before the well test choke manifold protect the surface equipment downstream of the filter. See Figure 5.5.
Figure 5.5. (a) Surface sand filter (b) Dual pot sand filter schematic
Sand separators (Figure 5.6) encompass a number of different designs. Some simply consist of large vessels situated before the separator and rely on the drop in the velocity of fluid entering the vessel to cause solids dropout, and others are fitted with internal devices such as cyclonic centrifuges to assist with solids separation.
Figure 5.6. Sand separator
Sand separators are not routinely supplied in a well test equipment package, but can be made available from the surface well test contractor with adequate planning notice.
Erosion monitoring is a safeguard that provides an early indication of sand production and possible erosion. Common monitoring techniques include
- Direct measurement using BSW samples
- Pipework thickness monitoring
- Erosion probes
- Acoustic monitoring
Samples taken from various points within the system, usually at the choke and the separator, provide some indication of the presence of sand, although this will not show if erosion is occurring. This may, however, provide a qualitative indication of sand production and an early warning of the potential for sand-related problems. BSW measurements are routinely taken on every well test so no additional cost or significant planning is required.
Thickness measurements made using an ultrasonic thickness meter are often used as a control for monitoring erosion on pipework. At any given point, a thickness measurement might vary depending on how the operator uses the tool. It is recommended that several checks be made at the same point to establish a reliable thickness measurement. During well test preparation and prior to any production, a representative number of thickness measurements of the pipework are recorded in order to establish a baseline, the number of sampling points varying according to the size of the setup. Fifty to a hundred pipe measurement points is not unusual. The points selected should include those most likely to experience erosion, choke outlets, elbows, reducers, and the like. Each sample point is marked and numbered, so that the same points are measured during successive surveys to establish any erosion trend. There may be occasions that warrant measurement of every elbow. This might be the case if the well test equipment has been in service previously, if its condition is uncertain, or if the probability for sand production is high.
Erosion probes (Figure 5.7) are sacrificial tubes inserted into the flow stream. When erosion exposes the inside of the tube to pressure, this registers on a gauge or an automatic switch to provide a warning that erosion has occurred. In order to be effective, probes should be placed close to those locations where erosion is likely to be greatest.
Figure 5.7. Erosion probe
More sophisticated probes use an electrical resistor (Figure 5.8) as the erosion target. The resistance change as the material erodes is measured and recorded at a computer. This type of measurement provides additional data for erosion rate and sand mass estimation.
Figure 5.8. Electrical resistance erosion monitor
Acoustic devices detect the sound generated by the impact of solid particles on the inside pipe walls because they rely on noise detection. The sensors are ideally fitted just after pipe elbows or chokes.
Pipework Sizing
In our earlier discussion, fluid velocity inside production pipework was identified as a factor in erosion. For a given mass flow rate, the velocity of the fluid is greater in smaller pipework because the same mass of fluid must pass the same point in any given time period.
At higher velocities, friction forces between the fluid and the pipe walls are greater and result in increased pressure losses along the entire production system. Higher system pressures are therefore necessary to achieve high flow rates with smaller pipe. Selecting the right pipe in order to achieve the desired production rate for the available operating pressures is an important aspect of well test design.
Since the available pressure from the wellhead is fixed, then varying the size of pipe is the only variable available in order to improve the maximum flow rate. Provided pressure losses due to friction forces are not greater than about half the available wellhead pressure, then the desired flow rate is achievable. In other words, a direct relationship exists between achievable flow rate and pressure loss due to friction. To determine the total pressure loss, calculations are performed for each pipe section, working from the burner head and gas flare tip to the separator and the choke manifold or wellhead. Knowing the available wellhead pressure from nodal analysis, the engineer can determine whether the desired flow rates are achievable. If not, the engineer must select larger diameter pipe. Refinements to the calculation include equivalent pressure drop data for the valves and fittings in the system.
Similar calculations performed for vent and pressure relief lines validate the pipework sizing for these devices. It is essential that pressure relief valves and pipework be able to transport the maximum possible production rate safely. Some common well test pipework sizes and specifications are listed in Table 5.1
Table 5.1. Common Well Test Pipework
| Size | Material | Pipe Schedule | Wall Thickness | Working Pressure | Application |
|---|---|---|---|---|---|
| 3” | A106 Grade B or A333 Grade 6 | XXS | 0.674” | 10,000psi | High Pressure Fluid |
| 3” | A106 Grade B or A333 Grade 6 | 80 | 0.300” | 2,500psi | Low Pressure Oil |
| 4” | A106 Grade B or A333 Grade 6 | 80 | 0.337” | 2,300psi | Low Pressure Gas |
| 6” | A106 Grade B or A333 Grade 6 | 80 | 0.432” | 2,250psi | Pressure relief lines |
All pipe in the above table will be H2S service in accordance with NACE MR 01 75
Nodal Analysis
Nodal analysis is a modelling tool used by drilling, subsurface, and well test engineers to help achieve an optimum well design in terms of perforations, tubing size, and fluid and underbalance design, as well as to provide some of the key data inputs for the design of surface facilities.
Nodal analysis models both the inflow performance of reservoir fluid into the wellbore and the outflow performance of reservoir fluid through the tubing.
The inflow performance relationship (IPR) plots the drop in reservoir pressure with the production rate to produce a characteristic curve for a given set of conditions, that is, reservoir permeability, thickness, pressure drop, wellbore radius, fluid viscosity, and skin (see Figure 5.9).
Figure 5.9. (a) Inflow performance relationship (b) Outflow performance relationship
The outflow, or tubing performance, plots pressure loss in the tubing against increasing flow rate for a given set of conditions, including fluid weight, friction losses, and wellhead pressure. Friction loss in turn is a function of the tubing size and condition. The plotted results produce a characteristic outflow performance curve.
Plotting these two curves together provides a pressure and corresponding flow rate for a given position along the tubing or at the wellhead. (see Figure 5.10)
Figure 5.10. Inflow versus outflow, tubing sensitivity
The same plot may be produced to compare different tubing sizes and production rates. These comparisons or sensitivities as they are referred to, help the well test planning team to select the optimum tubing. The data from nodal analysis provides pressure and production data that contributes to well design, surface process equipment design, and the well test procedure. This calculation is performed by the subsurface team since it derives from an understanding of the reservoir model and downhole conditions. The well test engineer may provide input on perforation data and available tubing sizes. Since nodal analysis provides such fundamentally important inputs, it must be completed early in planning, during the preparation of the well test Basis for Design.
Tubing Stress Analysis
Tubing stress analysis calculates the forces and/or movements that act on the tubing, casing, and packer as a result of the weight of tubing, well pressure, surface applied pressure, and temperature effects. Its purpose is to select suitable tubing or to validate the tubing and packer design selected for the well test. Because it influences tubing selection, it must be carried out early in planning so that the tubing size and type can be specified in the Basis for Design.
Nodal analysis helps to determine a suitable tubing size capable of achieving the desired production rate for the well conditions, but the design must also consider the yield strength of the tubing. Under production conditions, tubing is subjected to various loads that can produce significant forces that are sometimes capable of exceeding the inherent strength of the tubing material. When considering yield strength, as with other equipment components, a safety factor is included. Typically, loads should not exceed 80 percent of yield strength in the case of new tubing. A larger factor of safety is required for old or used tubing and will vary according to material, age, and general condition.
In order to determine the forces acting on the tubing, the well test engineer must consider the operating conditions during the test when the various forces will be at their greatest. Tubing stress analysis calculations are performed using computer programs available to most resource companies and tubing and packer contractors. It is the well test engineer's task to ensure that the inputs for the analysis accurately reflect actual well test conditions. These inputs to the tubing stress analysis are the load cases that define the most extreme range of conditions which the tubing and packer may experience during the test. The well test engineer will discuss these load cases with the packer and downhole tools contractor to ensure they are correct. The initial conditions are those that exist in the well at the time the packer is set, that is, the hydrostatic weight of fluids in the annulus and tubing and surface applied pressure, if any. Maximum drawdown is the drop in pressure downhole associated with production of fluid at surface. The fluid hydrostatic inside the tubing will be at its lowest, while at the same time the pressure in the annulus will be the combined pressure of the hydrostatic annulus fluid weight and the pressure applied on top of this to maintain the tester valve in the open position. During shut-in, the tubing experiences maximum shut-in tubing head pressure, and the annulus is hydrostatic fluid weight only. Contingency kill considers the case where the tubing is full of gas and the annulus has maximum surface pressure applied to operate the secondary circulating valve. Table 5.1 lists a typical set of conditions considered for a well test.
The results produced by the calculation list the various ways in which the forces act on the tubing. Resource companies allocate design safety factors for each so that the tubing and packer do not experience loads outside of their design specifications. A typical set of design safety factors are listed in Table 5.2, it should be noted that these values vary from one resource company to the next.
Table 5.3. Tubing Stress Analysis Design Safety Factors
| Collapse | Burst | Tension | Compression | Triaxial |
|---|---|---|---|---|
| 1.1 | 1.25 | 1.6 | 1.2 | 1.25 |
Table 5.2. Tubing Stress Analysis Load Cases
| Operation | Tubing Fluid | Tubing Pressure | Annulus Fluid | Annulus Pressure |
|---|---|---|---|---|
| Initial Condition | Kill fluid | None | Kill fluid | None |
| Maximum Drawdown | Hot-Evacuated | None | Kill fluid | Tester valve opening pressure |
| Shut in | Gas | SITHP Gas | Kill fluid | Tester valve opening pressure |
| Contingency Kill | Gas | SITHP Gas | Kill fluid | Rupture disc pressure |
For every tubing stress analysis, the results must be compared against the resource company design safety factors. If any condition exceeds the designated safe limit, then the well test engineer must evaluate the suitability of the tubing and packer or, alternatively, consider procedural controls that avoid exposing the tubing to the conditions that give rise to the unsafe load. Such measures can only be made with an appropriate risk assessment and with well-defined procedural controls. Figure 5.11 illustrates a set of load cases more graphically.
Figure 5.11. Tubing stress analysis load cases
If the packer and tubing are fixed together, as in the case of a tubing conveyed packer, the forces acting on the tubing also act on the packer. In addition to the loads transmitted through the tubing, the packer also experienced forces directly as a result of pressure acting from above and below. All packer manufacturers provide packer design envelopes (Figure 5.12) that define the limits for the load conditions within which the packer will operate reliably.
Figure 5.12. Example packer operating envelope
Figure 5.12 illustrates a typical packer design envelope. The results of the tubing stress analysis are assessed to ensure that the load conditions do not exceed design specifications.
Hazard and Operability
When the components of well test equipment are assembled together, their varying specifications make the task of assessing the overall suitability of the system a complex one. To take an example, a high-pressure manifold, rated to 10,000 psi working pressure, will readily contain a 5,000 psi well head pressure, but downstream of this manifold, other devices such as separators, pipework, tanks, pumps, and burner heads cannot contain this pressure. Controls are required in order to ensure that this low-pressure equipment is not exposed to high pressure by accident and that equipment and personnel are protected from this and other potential hazards to the system.
A Hazard and Operability study (HAZOP for short) is a procedure that follows a standard in order to assess the suitability of a particular process system. The analysis is performed using the operating envelope for the test to define the extremes of conditions to which the equipment is exposed.
This procedure identifies the controls required for each of the conditions that can present a hazard to the process. The methodology within the various standards follows a similar set of steps.
- Assemble a representative team of experienced personnel with a relevant spread of technical knowledge.
- Divide the well test process equipment into logical nodes, that is, segments of the process that share the same specifications and are protected by the same safety devices.
- Define the operating envelope and specifications for each node.
- Apply a set of guidewords (variable conditions) to each node and identify production condition deviations produced by each variable, that is, High Pressure, Low Pressure, Gas Blow By, Liquid Blow by, Excess Temperature, Low Temperature.
- Agree on the controls required to protect the system from the deviation in conditions. The controls might include a combination of one or more of the following: indicator devices, alarms, automatic shutdown devices, pressure-relieving devices, check valves, flow restrictors, fusible plugs, spark arrestors, and control valves.
- The procedure provides a method for capturing the information from the HAZOP into a standard format called a safety analysis table (SAT). Each device is also marked on a piping and instrumentation diagram (P & ID), which becomes an important reference document for the scope of supply and the installation and commissioning procedure for the well test equipment at the well site.
The well test engineer plays a central role in coordinating the personnel and resources required for this process. Often, the HAZOP is facilitated by a third-party contractor specializing in this type of analysis process
Rig Interface Engineering
At a land-based well site, well test equipment other than support utilities such as water and power is supplied entirely by contractors. Offshore, most drilling facilities supply some of the equipment necessary for well testing, without which the preparation required for every well test would entail considerable engineering. This section describes the well test equipment that might be expected as part of the drilling facility scope of supply, together with a description of the utilities and other well test interfaces.
Pipework
Pipework utilized for surface flowlines and standpipes is generally separated into two material groupings, 4130 and 4140. These are alloys hot worked or extruded and suited to high-pressure applications, such as for derrick standpipes and high-pressure flowlines. In general, 4130 material is preferred; 4140 is a harder material and is not suited for sour service. A106 and A333 are material references for pipework applied to low-pressure applications and recommended by NACE. These materials are appropriate for working pressures of 1440 psi. A333 is suited for work at low and high temperatures, while A106 is not suited for temperatures below 0 Celsius.
In general, larger diameter pipe is preferred for gas pipework because it permits higher production rates, reduced back pressure, reduced noise, and reduced risk of flow erosion due to reduced fluid velocity. The pipework guidelines listed below provide some specifics in relation to well test pipework.
To avoid confusion, it should be noted that materials utilized in surface pipework differ from those used for tubing. Materials specified for tubing are identified by yield strength. For example, L80 or J55 refers to tubing joints with yield strengths of 80,000 psi and 55,000 psi, respectively. This type of tubing is not suited for surface pipework applications, it is cold rolled, welded, and treated, and it does not lend itself to welding to attach surface pipe fittings. These tubing sections are manufactured with threaded ends that permit connecting the tubing lengths as they are run into the well. Pipework Guidelines
- Where practicable, route pipework away from accommodation areas, lifeboats, escape routes, and other safety-critical areas.
- Route pipework clear of heat sources or areas where pipework may be exposed to impact from crane lifts.
- Use the most direct route between the well test area and the flare booms, allowing for the considerations above in order to minimize pressure losses.
- All pipework must be securely anchored using adequate clamps and brackets to restrict vibration and control reaction forces in the event of pipe failure.
- Minimize elbows where possible.
- Avoid low points where water and other fluids may sit and accumulate.
- Keep pipe flanges away from nonhazardous-rated electrical equipment
- Use pipework welding procedures as per ASME B31.3
- Make calculations for wall thickness, pressure, and temperature rating as per ASME B31.3.
- Make calculations for working pressure based on pipe wall thickness, and not on the hammer union end fitting often rated to higher working pressures than the pipe material.
- Make sure hydrocarbon-bearing pipework is sour service and complies with NACE MR0175, pipework material A106 Grade B, or A333 Grade 6 or equivalent. A333 is preferred.
- Use recognized hammer union fitting manufacturers, FMC and ANSON.
- A hammer union connector thread half comprising the elastomer lip seal shall be considered the “female” half and is utilized for the inlet of a section (see Figure 15.13).
- A hammer union connector that incorporates the “nut” and the hammer lugs is the “male” half and is utilized for the outlet of a section.
- 2 in. 602 Female can potentially connect to a 2 in. 1502 Male; for this reason 2 in. 602 unions are not recommended and on many facilities are prohibited.
- 2 in. 1002 has the same thread as 2 in. 602 and is prohibited in well testing.
- Articulated or swivel pipework should not be used on hydrocarbon lines.
- Threaded fittings should not be used; pipework sections and end fittings should be welded.
- Pipework supplied with full material traceability, welders certificates, welders procedures, pipework calculations, and as
built drawings. Substantial welded steel bracelets attached to the pipework should be used for specification and traceability
information.
Figure 5.13. Weco hammer union
Figure 5.14. Typical rig supplied well test pipework
Flanges, Studs, and Fittings
Bolted flanges are used in preference to hammer unions when metal-only seals are permitted or more desirable. Near the flowhead, high temperatures and high levels of CO2 and H2S dictate the use of metal-only seals. Elsewhere, bolted flanges are used where connections are not routinely broken between well tests. These are the intermediate connections joining various components of a piece of well test equipment, the choke manifold, steam exchanger, separator, diverter manifold, transfer pumps, and burner heads; all have some bolted flanges. Hammer unions are used on inlet and outlet connections to interconnect this equipment. The strength of the bolted flange connection is dependent on the makeup torque of the flange studs because flange studs are an item frequently changed during service work on well test equipment. They can be replaced using studs and nuts with the incorrect material. Compliant studs are stamped with a material mark at either end, L7 or B7. The flange studs must extend beyond the end of the bolt in order to achieve a full-strength connection. (See Figure 5.15.)
Figure 5.16. Photo corroded NPT thread
Figure 5.15. (a) and (b) bolted flanges
The industry has seen fatalities and serious injuries arising from the misuse of threaded fittings, in particular with corroded box threads that only provide partial thread engagement. Thread gauges should be used during maintenance and inspections to ensure thread fittings are in good order. The assigned pressure rating for each fitting size and material grade must be respected.
NPT (National Pipe Taper) is a common oilfield thread governed by ANSI/ASME B1.20.1. Common sizes in use include 1/8”, ¼”, ½”, ¾”, 1”, 1 ¼”, 1 ½”, and 2”. The smaller sizes in particular are used for high-pressure applications up to 5,000 and 10,000 psi. High-pressure fittings should be manufactured of stainless steel grade 316 (316SS). NPT threads have a slight taper and should not be confused or interchanged with National Pipe Straight (NPS); in addition, NPT threads require polytetrafluorethylene PTFE (Teflon) tape to achieve a pressure seal. This also acts as an anti seize to facilitate later removal of the fitting.
Well Test Equipment Placement Guidance Notes
The following notes provide guidance on issues relating to deck placement and general interfaces between the well test equipment and a MODU facility.
Escape Routes
Plan at least two independent escape routes from the well test area and consider providing a deluge to cover the primary route. Escape routes should be located on opposite sides of the well test area, so that if one escape were blocked, for example due to fire, then personnel located in the test area could access the alternative route located in the opposite direction. These should provide for walkways free from obstructions with adequate width and height clearance, so that personnel can move quickly without having to crouch or duck to avoid pipework or other obstructions.
Accommodation A60 Fire Walls
The well test equipment must be located as remote from the accommodation as possible. The accommodation bulkhead, together with any office units or locations where personnel are likely to be working during a well test and which are close to the well test area, must be protected by A60 fire walls.
Fire Alarms
Due to the noise levels frequently encountered during well test activity, it is recommended that the well test area be supplied with both visual and audible emergency alarms and activation switches located near the escape routes.
Deluge
The well test area should be supplied with suitable fire-fighting equipment. This may include a deluge surrounding the well test area capable of blanketing the well test equipment in the event of a fire and/or substantial fire monitors located so as to provide operators with a clear throw to the well test area. Monitors will not necessarily be located in the well test area since any fire associated with the well test equipment may render them inaccessible to the fire team.
Communications
Locate at least one handset along each escape route linked to the facility internal communications system. It is recommended that each handset be housed inside a sound-absorbing shield to facilitate better communications during testing.
Electrical Supply
Although air-powered equipment is recommended whenever possible, use of electrical power for some equipment is unavoidable. Typical electrical power requirements for a well test package are listed in Table 5.4.
Table 5.4. Common Threaded Fittings
| Thread Size | Working Pressure | Test Pressure |
|---|---|---|
| ½” NPT | 10,000 psi | 15,000 psi |
| ¾”-2” NPT | 5,000 psi | 10,000 psi |
| 2 ½”-6” NPT | 3,000 psi | 6,000 psi |
Like all electrical points on the deck of a MODU, the connections must comply with international standards for the use of electrical equipment in potentially hazardous environments.
Utilities
Instrument air, drill water, and seawater are utilized for many items of test equipment. Crowfoot connections are the most common connection for use with air and water supply. Fatalities and injuries have occurred through the misuse of these connections. Flexible hose connected to these supply points must be in good condition and secured to the end fitting with approved connector clamps. R-clips and whip checks must be used to secure crow's foot connections.
Table 5.5. Well Test Electrical Equipment
| Item | Location | Supply Voltage | Supply Current |
|---|---|---|---|
| Office Container | Well test area | 380–440 VAC 3 Phase | 25A* |
| Transfer Pump | Well test area | 380–440 VAC 3 Phase | 55A* |
| Steam Boiler | At least 20 m remote from well test area | 380–440 VAC 3 Phase | 25A* |
| Ignition System | Each flare boom | 110–240 VAC | 10A* |
| Lighting | Various | 110–240 VAC | 10A* |
Cement Unit
The cement unit is a contractor-supplied and -operated pump unit capable not only of high volumes and pressures, but also of precision work such as pressure testing and cementing. In preparation for well test operations, the cement unit is used to pressure-test equipment and to pump underbalance and kill fluids. Open top displacement tanks attached to the cement unit are normally used to store fluids in preparation for pumping operations. Because regulations prohibit filling these tanks with diesel, the cement unit must take a direct diesel supply from an alternative source, offshore the MODU motor room. This feature is not always available on every MODU and may require installation work in preparation for the test. The addition of such a line may also require a revision to the fire and explosion analysis in the MODU Vessel Safety Case.
The cement unit is also utilized to pressure-test the well test equipment and to calibrate well test production meters on the separator. The standard pipe configuration for a typical cement unit follows a standpipe from the cement unit to the drill floor, then down to the main deck via the well test flow line. Ideally, well test pressure testing occurs off critical path, but for safety reasons, pressure testing using the drill floor pipework is often prohibited while other operations take place. This imposes restrictions that may result in this operation occurring on critical path. The cost of installing a dedicated high-pressure test line between the cement unit and the well test area directly, bypassing the drill floor, might be justified for this reason.
Lighting
Well test activity is a 24-hour operation; thus, adequate lighting is essential to ensure the safe continuity of operations. Lighting must cover the entire well test area to enable personnel to operate equipment and to see instrumentation clearly, as well as to clearly illuminate the escape routes. All lighting must be certified for operation in hazardous areas. Hand held torches must also be intrinsically safe for use in hazardous environments.
Flare Booms
Offshore, hydrocarbons produced during a well test must be disposed of in a manner that is safe for handling and minimizes the risk for environmental contamination. On a production facility, hydrocarbon products might be taken into the production line. However, this option is not available on an exploration facility. A practical and widely utilized method for disposal is flaring. This activity generates significant heat radiation that must be controlled. For this reason the flaring takes place at the end of a flare boom, which extends from the side of the facility to reduce the effects of head radiation. There are practical limits to the length of the flare boom imposed by the weight and strength of the boom and the support structure. In practice, flare booms might vary in length between 20 m and 30 m. Because many drilling facilities are moored and therefore cannot orientate if the wind direction changes, most facilities carry two flare booms, one on either side to allow continuity of operations regardless of wind direction.
Figure 5.17. Cement unit P & ID
Many facilities provide their own flare booms as part of their scope of supply for well test equipment. Contractor-supplied flare booms can be installed at a facility, but this type of installation requires substantial planning and engineering work.
The following list provides some guidelines relating to flare boom installation on an exploration facility.
- Position flare booms away from the accommodation structure.
- Ensure that facility cranes on both sides have adequate reach for installation and removal of booms and burner heads.
- Assess the deck structure providing support to the booms and any kingpost supports in order to establish that it has adequate strength for the loads.
- Where practicable, minimize the distance between the well test area and the booms.
- Consider the location of other equipment and areas that may be affected by heat radiation, electronic navigation equipment, flammable paint stores, fuel tanks, pressure vessels, lifeboats, and lifesaving equipment and general work areas.
Rig Cooling
Heat radiation from flaring will act on every surface in line of sight from the source, including the facility structure, fuel tanks, columns, support legs, accommodation, paint stores, cranes, tanks, containers, lifeboats, and electrical equipment. By raising the temperature of a surface, the object in question may experience damage due to overheating. Its contents may catch fire, or a pressure vessel may experience an overpressure. In order to help control these hazards, most facilities provide cooling systems designed to create a water shield between the flare source and the side of the facility. The water shield absorbs much of the radiated heat, reducing the intensity to a safe level. The effectiveness of the water shield depends on the amount of heat radiation, the pumps supplying the water to the cooling system and the general condition of the pipework and diffusion nozzles. The water shield in itself may not be the only control; heat shields provide an effective barrier to protect personnel and equipment. Heat shields are blankets manufactured from heat-resistant material similar to that utilized in fire suits and suspended along the side of the facility or blanketed over equipment for protection. Unlike water cooling, heat shields are passive; that is, they are not dependent on the continuous operation of pumps to be effective. Heat shields are not normally supplied by the facility.
Compensator System
The compensator system is designed to reduce the impact forces arising out of the relative motion of a floating facility and the well. During installation and retrieval of the workstring, the potential for a high impact resulting in equipment damage could occur between upsets in the workstring such as at the packer and subsea test tree against upsets in the well, such as liner hangers, the wellhead and the BOP. The compensator introduces an air cushion acting on a piston, as the weight on the workstring drops when it contacts a fixed point inside the well, the force is transmitted to the piston which compresses the air and so cushions the effect of the impact. (See Figure 5.18)
Figure 5.18. Compensator system
Drilling Rig P and ID
The schematic in Figure 5.19 represents a typical drilling rig tank and pipe configuration. Drilling fluids are stored in the pits. Mud pumps transfer this fluid to the workstring or the annulus as required. The returned fluid travels through the gas separator or directly to the shakers for filtering and then back to the pits or overboard. The trip tank provides the driller with a reservoir to store fluid in order to rapidly top up the well volume or to take returns in the event of gains and generally to provide a means of monitoring fluid volumes in the well.
Figure 5.19. Drilling rig P & ID
Facility Design and Engineering Report
This report describes the design and engineering input to the surface well test facility. The name and content of this report might vary from one contractor to the next, but the well test engineer reviews this report to ensure that the most important engineering features are described accurately and in sufficient detail so as to demonstrate that the facility is fit for its stated purpose.
Typical elements of a well test design report
- Reference standards
- Operating envelope
- Process equipment
- Equipment placement
- Set of drawings (layout, hazardous areas, process and instrumentation)
- Back pressure and pipe-sizing calculations
- Safety system engineering (philosophy)
Reference Standards
A reference standard provides a control to ensure that a process, together with the product that is the output of a process, is free from faults and capable of performing its intended purpose — in other words is fit for purpose. One objective of a well test design report is to demonstrate that the engineering input to the design of a surface well test facility is fit for purpose. In order to achieve this objective, the engineering input to the design adheres to various standards, including welding, vessel design codes, pipework, electrical standards, and other engineering standards that apply to valves, seals, and other components of test equipment. Listing the reference standards in the report provides a means of auditing the design.
The well test engineer reviews this report when planning has advanced far enough for the well test contractor to complete the detailed design work. This is often close to the mobilization of equipment to the field. The well test engineer assesses the report for completeness and accuracy, including a check to ensure that appropriate industry standards have been applied to the design. Under some regulatory environments, this report is subject to review by an independent well test engineer or organization, sometimes called a peer review or validation. Often, an external observer not involved with previous planning can identify issues, omissions, and mistakes overlooked by those directly connected with planning.
Operating Envelope
The operating envelope is the set of production conditions for which the process equipment has been designed. Those conditions are pressure, temperature, fluid type, production duration, and production rate. It is important that these conditions are listed in the design report, for a number of reasons. First, to ensure that the correct conditions have been used for the design work, the contractor obtains this list of conditions from the Basis for Design document prepared by the well test engineer. Often, production conditions are revised during planning based on additional or refined data. The well test engineer is responsible for ensuring that the contractors performing the design work use the current available data. The Basis for Design document is a controlled document for this reason. Secondly the reason for ensuring that the operating envelope conditions are current is for reference. Personnel including contractors and supervisors at the well site must be aware of the operating limits for the system so that they can take the necessary steps to ensure that none of those conditions are exceeded. Finally, the information in this document provides a reference for regulators, managers, and third-party design verification engineers.
Process Equipment
The design report lists the equipment that makes up the process facility. Each item has its own purpose and set of specifications. The well test engineer reviews this list referencing the contract and planning documentation to ensure it is comprehensive and accurate. The specifications must be adequate to meet the conditions defined by the operating envelope and the standards applicable to each component consistent with the agreed-upon well test design standards. That is, the design standards must meet industry, regulatory, company, and contract specifications.
Equipment Placement
Well test equipment brings with it hazards that are not normally encountered during drilling operations. The storage and handling of hydrocarbons on deck requires careful management. For this reason, most offshore rigs assign a specific area for the location of well test equipment. The designated area locates well test equipment, as far as practicable, from the accommodation and from other areas where well test activity might clash with essential facility equipment or services. The Vessel Safety Case assesses hazards associated with the placement of well test equipment in this area. Only in exceptional circumstances will this location change to meet the needs of individual operations. Completions or coiled tubing placement might necessitate moving well test equipment to a new area. Assigning a new area for well test use constitutes a significant change and requires formal risk assessment. Factors to consider with equipment placement include normal rig operations, fire equipment location and suitability, escape routes, deck loads, crane capacities, hazardous equipment, other work areas and work activity, and the safe and practical operation of the well test facility itself. These issues are considered during the rig site visit and in consultation with rig management during planning. The final agreed placement is captured with a drawing showing the location of each of the main well test equipment components. This drawing also identifies areas required for laydown, preparation of equipment, subassemblies, TCP guns, and transport containers and baskets. A wet weight, that is, the weight of each component when filled with seawater and dimensions are needed to ensure that deck loads are not exceeded.
Table 5.6. Process Equipment List and Specifications
| Item | MAWP MPa (psig) | Tempmin Celsius | Tempmax Celsius | Design | Nominal Size |
|---|---|---|---|---|---|
| Flowhead | 69 (10,000) | – 20 | 120 | API 6A | 76 mm (3”) |
| HP Flexible Hose | 69 (10,000) | – 20 | 100 | API 16C | 76 mm (3”) |
| Shutdown Valve | 69 (10,000) | – 20 | 120 | API 6A | 76 mm (3”) |
| Choke Manifold | 69 (10,000) | – 20 | 120 | API 6A | 76 mm (3”) |
| Steam Exchanger | 69 (10,000) | – 20 | 120 | ASME API 12K | 1281 kwh (4.3 MMBTU) |
| Boiler | 1.17 (170) | 0 | 100 | ASME 8 Div1 ANSI B31.3 | 1281 kwh (4.3 MMBTU) |
| Separator | 9.7 (1,440) | – 20 | 120 | ASME 8 Div1 ANSI B31.3 ASME B16.5 | 1.7 MMm3 (60MMSCF)/Day |
| Oil Manifold | 9.7 (1,440) | – 20 | 100 | ANSI B31.3 ASME B16.5 | 51 mm (2”) |
| Surge Tank | 0.34 (50) | – 20 | 88 | ASME 8 Div1 ANSI B31.3 ASME B16.5 | 12.7 m3 (80bbl) |
| Transfer Pump | 2.0 (300) | – 20 | 100 | ANSI B31.3 API 610 API 682 | 795 m3 d (5000BPD) |
| HP Pipework | 69 (10,000) | – 20 | 120 | ANSI B31.3 | 76 mm (3”) |
| LP Pipework | 9.7 (1,400) | – 32 | 121 | ANSI B31.3 | 76 mm (3”) |
| LP Pipework | 9.7 (1,400) | – 32 | 121 | ANSI B31.3 | 102 mm (4”) |
| Burner Heads | 6.9 (1,000) | – 20 | N/A | ANSI B31.3 | 477–1908 m3 d (3000–12000BPD) |
A layout drawing is a plan view showing the well test equipment in position on the deck of a facility or well-site location.
A hazardous area drawing marks on top of a layout drawing those areas considered hazardous during a well test operation, the hazard being the presence of flammable hydrocarbons. These areas can be further classified if the level of hazard changes for different parts of the process. Areas where hydrocarbons are continuously present in the atmosphere are more hazardous than areas where hydrocarbons are present for only short periods or not at all. Such classifications identify each area as a zone 0, 1, or 2 accordingly.
A well test hazardous areas drawing (Figure 15.21) incorporates existing hazardous areas specific to the facility with those introduced by the well test. A hatch overlay on the drawing highlights the hazardous areas and is sometimes color coded according to the zone classification.
What is this drawing used for? The presence of hydrocarbons in the atmosphere is a hazard that has the potential to lead to fire and explosion should the right conditions occur, that is, an ignition source such as a spark from an electrical circuit, welding equipment, or motor. The drawing defines areas within which all sources of ignition or possible ignition must be removed. Electrical equipment not certified for hazardous areas operations must be isolated, including power points, light switches, exhaust/intake fans, motors, welding, and cutting equipment. Hot work and other unnecessary activities are shut down during well test operations. In particular, crane activity over live well test equipment is prohibited.
Figure 5.20. Well test hazardous areas drawing
This drawing is referenced during planning in order to optimize the routing and layout of equipment, and it is also utilized by rig management to review the equipment setup to ensure that all ignition sources are safely isolated.
A piping and instrumentation diagram (P & ID) is a drawing or, in some instances, a set of drawings, which represents the entire surface well test process system detailing equipment, piping, and instrumentation (Figure 5.22). It serves several purposes. As a scope of supply document, it indicates all of the equipment required in the surface equipment process, including specifications and details of type size and location of crossovers, pipework, instrumentation, and safety devices. It also indicates the assembly order for all equipment and so provides a reference to well site management as a check for auditing the equipment setup. The P & ID also communicates details for the proposed setup to other parties, including the regulator, validation engineer, other planning team members, and resource company management.
Figure 5.21. (a) Basic well test P & ID (b) P & ID symbol key
Figure 5.22. Deck load drawing
Deck Load
An important rig interface is the weight of the test equipment and the capacity of the deck to support it. The deck load capacity is available from the owner and is specified in the facility description section of the Vessel Safety Case. This information is required by the class society that provides the MODU certification. Not all deck areas will have the same capacity. Some areas, such as BOP housings, accommodation units, wing decks, lifeboat decks, and a number of other areas around the rig, are designed for very specific applications and often have little or no load-bearing capacity. Pipe decks, riser decks, and dedicated laydown areas typically have the greatest load-bearing capacity. Load capacity is determined by the type of deck plating and deck beams fixed to the plating to distribute loads and the support provided below the plating that can contribute the greatest part of the strength. Load-bearing capacity has two components: the overall load capacity of the area in question and the unit area load capacity. Metric units are given as kgs/m2, while imperial units are given as psf (pounds per square foot). A drawing of the deck provides one of the best means of presenting this information with hatched shading to identify areas with distinct load capacities (Figure 5.22).
Unit load capacity is particularly important for heavy loads that have a small footprint on the deck. When considering well test equipment, a table detailing the wet weight and footprint dimensions for each item is used to calculate and present the load contribution of the well test equipment. Wet weights are the weights of the various items of equipment when full of fluid, usually calculated based on seawater. Concentrated deck loads for items such as vertical surge tanks are often a concern and frequently exceed the deck load capacity, particularly on older facilities. In order to overcome this problem, the surge tank can be mounted on spreader beams to distribute the load or located on deck directly over a major supporting member. Some other controls involve restrictions as to the maximum fluid levels permitted in the tank.
Figure 5.23. Well test equipment loads
Back Pressure and Pipe Sizing Calculations
The report must provide details of the pipe sizing and back pressure calculations (see Figure 5.24) to demonstrate the suitability of the pipework selected for the process equipment. The calculations must also include the line sizing for pressure safety valves. It is essential that pressure relief pipework and valves are capable of transporting fluids at the maximum possible production rates in order to protect equipment and personnel. Should this pipework restrict the flow at high rates, the inflow to the system will potentially be greater than the outflow and exceed the pressure-containing capacity of the equipment.
Figure 5.24. Pipe sizing
Safety System Engineering
This section describes the safety philosophy behind the engineering design. A typical approach incorporates three levels of safety protection, although the first level is not an engineering control per se because it requires manual activation of the emergency shutdown system (ESD). Well test operations, unlike production operations, are continuously attended, such that manual intervention is available at all times. Important features of this level of protection are the location of the ESD manual switches, which must be selected so that they are readily accessible to personnel within the well test area and the instrumentation providing an indication of the status of the process. Monitoring of the process takes place locally, with gauges fitted to the process equipment and remotely with a computer acquiring and displaying the data to a technician at a remote data-gathering location.
The second level of protection is automatic shutdown. Automatic switches located throughout the process equipment sense the conditions within the process and activate the emergency shutdown system if the conditions sensed by the switch exceed a preset value. The settings and locations for each switch are determined during the HAZOP and are indicated on the P & ID.
The third level of protection is automatic pressure relief to a safe area. Pressure safety valves (PSVs) fitted to vessels and pipework are preset to open at or below the safe working pressure of the device to which they are attached. Calculations are performed to verify that the design of the PSV is such that the maximum throughput of fluid from the well can be handled safely by the device. Unlike the first two levels of protection which involve a delay between an unsafe condition occurring and the shutdown system activating, the PSVs activate immediately to vent excess pressure and protect personnel.
Design Review
The engineering controls incorporated into the well test design are the subject of successive reviews (Figure 5.25), initially by the contractor preparing the technical response for the resource company, followed by the well test engineer and the resource company planning team, and finally by an independent, regulator-approved, review engineer. This third reviewer is mandatory in only some parts of the world. In either event, the review of the engineering input to the design requires a design report that details the preparations made by the contractor, the standards list providing an audit reference. The review must also include an assessment of equipment maintenance and certification records to show that the equipment has been prepared in accordance with the information detailed in the design report.
Figure 5.25. Design review flowchart
