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Graham Blackbourn: Blackbourn Geoconsulting

It is now about twenty years since geoscientists working for oil and gas enterprises within Russia and the Central Asian republics began to speak regularly with their counterparts in companies from other parts of the world, and it has been an interesting learning process for both sides. This article is the first in a series that will review the geology and petroleum potential of a number of the hydrocarbon provinces P both frontier and mature P within this vast area, and I will begin by attempting some type of wide-ranging overview. But it is difficult in a short article such as this to be both wholly objective and informative when covering such a large topic, and as someone who has had the privilege of working in many parts of the FSU over the past 20 years (indeed I first toured the Soviet Union in 1975), I have taken a very personal interest in the industry. So I make no apology that this first article at least is presented from a more personal standpoint.

Even the choice of twenty years as a period to examine is based on my own history. There had been some limited cooperation between oil companies in the East and the West for some decades before the break-up of the Soviet Union in 1991. Chevron's involvement in the Tengiz field on the West Kazakhstan Caspian coast during the 1980s comes to mind, and by 1989 it was apparent that new opportunities were opening up. That is why, when I established my own consultancy business in that year, having left a job as a geologist in a large oil company, I began to look actively in that direction. On the basis of a smattering of Russian picked up during a short course at school, and some technical translation, I offered my services as a consultant to western companies seeking to invest in the Soviet petroleum industry and needing to know more about its petroleum provinces and systems. And late in 1991 I embarked on an extended and somewhat bewildering tour of parts of Russia, Azerbaijan and Kazakhstan, while the political system was breaking down and the future shape of these countries was far from certain.

That trip, thanks to the generosity of contacts in Rostov State University, included several weeks viewing the oilfields of the North Caucasus, including several areas that have since become difficult to reach. It is a highly varied and once-prolific hydrocarbon region, now largely depleted. But despite well-known political hotspots, I am surprised by how few enterprising small companies from the West have sought to invest in field rehabilitation projects there, and several underexplored plays remain. I am convinced that significant potential remains in the North Caucasus for the small player prepared to take a risk.

But in the early 1990s the South Caspian beckoned, and a short hop over the Great Caucasus took me back to Azerbaijan where hopeful oil and gas executives tempted by rumours of massive remaining reserves were vying for acreage. But continuing political uncertainty and differing expectations from both sides meant that few deals were done in those early years, and others quickly came unstuck. The story was similar on the other side of the Caspian in Turkmenistan, where western companies like Bridas and Larmag suffered mixed fortunes with their ventures in the West Turkmenistan Basin. But the great thing for a western consultant working in the newly independent republics around the Caspian during the 1990s was that, as one became difficult to work in, another rose to favour for a while. I was called upon to work with Oryx who were negotiating to develop an oilfield on the Kazakh coast: Arman. That was an exciting project, as I quickly discovered that Arman's main Mesozoic producing horizons outcrop at the surface in the Karatau hills of Central Mangyshlak, leading to extensive fieldwork in the desert to develop reservoir models. That in turn led to further work on a number of other fields with the same reservoir, notably North Buzachi, then operated by Texaco, together with fields in the South Mangyshlak Basin. For a while, although it was the major fields in the North and South Caspian that were making headlines, much of the real progress was taking place "under the radar" in Western Kazakhstan.

But late in 1994, three and a half years of negotiations between Azerbaijan and an international consortium of oil companies headed by British Petroleum ended in the signing of the "Contract of the Century" for development of the offshore Azeri, Chirag and Guneshli fields. That drew attention back to that country, and for a while other companies poured in, although apart from BP's discovery of the Shah Deniz gas field, many of the exploration and development projects that ensued saw limited success. A second wave of interest also developed in Western Turkmenistan, where the government had learned useful lessons in dealing with foreign investors. Several of the projects that got off the ground at that time remain successful, including redevelopment of the Burun field, then operated by Monument, with which I was involved, and Dragon Oil's redevelopment of the fields in the offshore Cheleken block. But Turkmenistan became averse to new foreign involvement, and from the late 1990s for nearly a decade it became a more difficult place to do business.

The great thing about the petroleum provinces around the Caspian and Caucasus regions is that they are so diverse, with a wealth of opportunities for players of all sizes. In many areas there is an existing and well-developed infrastructure (admittedly in many cases in great need of modernisation) together with local markets. There is also, and this was sadly misjudged by many of the western companies when they first came to the region, a highly intelligent and well-educated local workforce. Perhaps one of the chief reasons for failure of investments during the 1990s, apart from cultural and commercial misunderstandings that were all-too-common on both sides, was an automatic assumption by some western field-development teams that their know-how would inevitably lead to discovery of new reserves and enhanced production. It's certainly true that a lot of fields were in great need of new investment and modern technologies, but in the absence of these the Soviet technicians had earlier used sheer brainpower and inspired innovation to maximise the potential of the tools they had available. The expected improvements following the application of western technology, sometimes applied less intelligently, were not always forthcoming.

This was particularly the case in some of the less prolific provinces where Soviet production companies had not been spoiled by a lengthy portfolio of prospective structures, and production profiles stretching well into the future, but where the task had been to eke out dwindling reserves. It soon became apparent in these areas P and several projects I worked on in Georgia and the Ukraine come to mind P that the most effective strategy for new investment was usually to change as little as possible, but simply to ask what equipment was needed to enhance productivity, and to supply whatever was requested (which often was not very much!).

Throughout this time I had been trying to make inroads into Russia, and had been involved in several projects in Siberia and parts of Southern Russia. Russia is a big country, and politicians in Moscow at that time were understandably only really interested in progressing the largest projects, with the biggest investors who generally had there own staff and didn't need help from small consultancies like mine. So I had little hands-on experience of the big Russian projects during the 1990s such as the onset of development around Sakhalin Island in the Far East, and in Western Siberia. But through time, as Russian legislative and fiscal rules became better-established and more transparent, it was easier for western companies to start doing business there, and I became more involved in work on-the-ground.

In recent years, interest has inevitably been developing in the Russian Arctic, especially offshore where the melting of sea ice is likely to expose wide areas of the continental shelf to exploration in coming decades. And in the far south of the former Soviet Union, massive new gas discoveries in the Amu Dar'ya Basin of Turkmenistan, combined with a more welcoming approach to foreign investment from that country, are attracting further interest to the eastern republics of Central Asia P including the basins of Eastern Kazakhstan, Uzbekistan, Tajikistan and Kyrgyzstan. There are few areas where significant problems are not encountered P and the geological problems that I am mostly involved with pale into insignificance compared with those associated with the remoteness of many of these areas, the lack of infrastructure, political uncertainly, and also cultural differences which can create misunderstandings between the parties in commercial ventures. But with the growing need for secure energy supplies around the world in the face of depleting reserves, and with the goodwill that I have almost universally encountered during my twenty years of experience working in Russia and Central Asia, I have little doubt that all of these areas will increasingly benefit from continuing mutual co-operation between the players in the international oil and gas community.

In future articles, Graham Blackbourn will describe the petroleum geology and the future prospectivity he perceives in some of the hydrocarbon provinces of Russia and Central Asia.

Labels: Blackbourn Geoconsulting, Central Asian republics, Kazakhstan, oil, oil gas Russia

posted by The Rogtec Team @ 17:07  0 Comments

By Sandy Williams, ALP (Artificial Lift Performance), & J F Lea, PLTech LLC

A PCP system is made up of three principal components:

1. the downhole pump comprising of the rotor and stator
2. the rod string which provides the torque to turn the pump
3. surface drive system (drive unit, speed reducer and prime mover)

Figure 1 - Typical PCP System Configuration


Figure 2 - PCP Installation, hydraulic drive

Pump Operation

• the pump consists of a rotor and a stator and function in a similar manner to a downhole mud motor.
• in simple terms the pump can be thought of as a conveyor belt on an assembly line, the faster the conveyor belt the more production is obtained.
• within the pump a series of cavities are formed between the metal pump rotor and the rubber stator, as the rotor turns the cavities spiral up the pump from intake to discharge carrying the well fluid through the pump.
• the rotor has the shape of an external spiral (or helix) machined onto its surface while an internal spiral with one more lobe is moulded into the surface of the stator. The pitch of the helix of the stator is twice that of the pitch of the rotor.
• the constantly sweeping seal line between the stator and rotor facilitates the transport of entrained gas or solids.
• the pumped fluid provides lubrication between the stator and rotor.
• operating depth up to 8000ft.
• maximum head approx 11800 ft of head or 5112 psi of differential pressure across the pump.
• production rates 5 - 5300 BFPD.
• Pump speed 100 - 1000 RPM although for oilfield operation, speeds of 100 - 500 RPM are more typical.
• pump displacement is quoted by manufacturers in terms of fluid volume per day per rpm.
• operating temperature approaching 350 deg F (elastomer limitation)

Figure 3 - One manufacturer's rate/head chart

PCPs are particularly well suited to pumping the following types of fluid:

• solids in suspension
• high viscosities
• abrasive slurries
• solids, liquids, gas mixtures
• oil and water mixtures without emulsification

Since the PCP is a positive displacement pump its performance is not affected by pressure across the pump. However, with increasing pump differential the seal between the individual cavities is not adequate and slippage of the pumped fluid takes place resulting in a drop in pump efficiency. Pump efficiency is a function of the interference fit between the rotor and stator and the viscosity of the fluid pumped.

Figure 4 - Pump curve for a PCP rated for 170 bfpd per 100 rpm and a maximum head of 4000 ft H2O. Note: drop in efficiency with increasing head, increasing HP and increasing head

Figure 4 shows a pump curve for a PCP. Head is plotted on the x-axis and flowrate is plotted on the y-axis (note this is the opposite of an ESP pump curve); flowrate only increases with increasing RPM. With increasing pump head the flow rate is initially constant until slippage starts to occur in the pump; pump flowrate then drops with increasing head.

PCP pressure limitation is a function of:

• stator material
• fluid properties (mainly viscosity)
• interference fit between stator and rotor

Total power system efficiency is usually higher for PCPs than other forms of artificial lift system, as demonstrated by the following table:


Pump Geometry
The pump consists of two helices, one inside the other, which constitutes a helical gear:

• the metal rotor, the internal one, is a simple helix;
• the soft stator, the external one, is a double helix with twice the pitch length of the rotor.

The geometry of the assembly is such that it constitutes a series of identical, separate cavities. When the rotor is rotated inside the stator these cavities move axially from one end of the stator to the other, from suction to discharge, creating the pumping action.

Pumps are described by the ratio of lobes created by the rotor and stator geometry. The most typical pump for oil production is a pump with a 1:2 geometry is referred to as a single lobe pump and creates geometry as follows:

At any cross-section the number of cavities is equal to the number of lobes on the stator i.e. for a 1:2 geometry there are 2 cavities 180O apart. Cavities are one stator pitch in length. One cavity starts where the other ends. The pitch of the rotor is one-half that of the stator.

In addition to single lobe pumps some manufacturers have designs for multilobe systems, where additional lobes are added to the rotor and stator.

Pump Displacement
Pump dimensions are identified using the following terminology:

At any cross section of the pump the area of fluid is equal to:
And the volume of fluid per cavity is equal to:

Taking into account units the theoretical pump displacement (single lobe pump) can be determined from:

where

PD = pump displacement (bbl/day/rpm)

The same equation is applicable for calculating flowrate using metric units if the constant is changed to 5.7E-6. The flowrate calculated will be in m3/day/rpm.

and total flow is calculated as:

where

Q = flowrate (bbl/day)
RPM = Pump rotational speed (RPM)

The calculated Q will differ from actual production rates at surface due to:

• inefficiency (slip/leakage) in the PCP
• downhole fluid volume will be higher than that at the surface (Bo effect).

Volumetric efficiencies of 70 – 80% are typical.

PCP manufacturers do not usually publish figures on the pump eccentricity, diameter of the rotor and stator pitch and so it is difficult to manually calculate pump rates. Instead manufacturers provide a pump curve and a value for displacement (bbl/day/rpm) and maximum pressure differential rating in terms of head or psi for a specific rotor elastomer.

Pump Nomenclature
Historically, PCP manufactures have not used the same convention for naming of pumps although most pump names have numbers in the name that provide an indication of pump displacement and maximum differential pressure in either metric or imperial units e.g.

Moyno 50-N-340 - maximum head of 5000 ft displacement of 340 bbl/day/100rpm,.
PCM 15-TP-1200 - displacement of 15 m3/day at 500 rpm with zero head, maximum head of 1200 m.

In order to know what each pump name meant it was necessary to know the manufacturer and their designation of pump type. Not, only was their nomenclature different but so were their graphs of pump performance.

Through ISO 15136 manufacturers are moving to use one standard terminology which will simplify the understanding of pump types. Under this standard the following terminology will be used for stators:

vvv-hhhh-eee

where
vvv = nominal capacity per rpm expressed in units of cubic metres per 100 rpm
hhhh = nominal head rating (metres of water)
eee = the elastomer code

and for rotors:

vvv-hhhh-rrr

where
vvv = nominal capacity per rpm expressed in units of cubic metres per 100 rpm
hhhh = nominal head rating (metres of water)
rrr = the rotor size code

Pump Stator
The pump stator consists of a metal housing with the elastomer stator bonded to the wall of the housing. The length of the housing may vary depending on the number of stages required to support the pressure differential across the pump. A rule of thumb is that a pressure differential of 65 psi/stage is acceptable.

Correct elastomer selection is the key to pump operation and longevity. When installed in the well, the elastomer will most likely swell use to temperature and well bore fluid effects. Being able to know the degree of swelling, will then allow selection of an appropriately sized rotor. In some operating areas where elastomer swelling is an issue, the rotor will be changed with time to a smaller rotor.

It is strongly recommended that elastomers are tested using well fluids to allow selection of the most appropriate elastomer type for the well conditions.

The following provides a list of some of the aspects that need to be taken into account in specification of the elastomer:

• temperature
• solids
• well fluids
• chemical treatments (scale / corrosion inhibitor, acid etc)
• bottomhole pressure relative to fluid bubble point
• gas contaminants (e.g. H2S and CO2)
• aromatics

The correctly specified elastomer needs to be able to seal against the rotor but also needs to have the following properties to a greater or lesser degree depending upon the application:

• gas permeation resistance
• oil resistance
• abrasion resistance
• tensile strength
• ductility
• hardness
• temperature resistance

Prior to a PCP being applied in a given operating area it is useful to perform tests to determine the suitability of a given elastomer in the wellbore fluids - particularly swelling of the elastomer. Trial and error are often used to set the pump in a test environment and allow the elastomer to swell in field operation, adjusted to finally an acceptable value.

Suitability of elastomers to a given application is summarised by the following table:


Pump Rotor
The rotor is normally 4140/4150 Carbon steel chrome plated with a coating. The purpose of the coating is to increase lubricity of the rod in the stator, resist corrosion and resist wear from solids. The coating is typically chrome but this may change with well conditions. In acidic conditions (< style="font-weight: bold;">Rod String
The function of the rod is to:

• withstand axial roads
• transmit torque to the rotor

In design of a rod system the following issues need to be considered:

• weight of the rod and rotor
• maximum stress in rod (combined torque and load)
• yield Strength of rod material
• operating environment (salt water, H2S)
• fatigue loading

Axial loads on the rod are due to the rod weight, the weight of the rotor and a piston force due to the differential pressure across collars and centralisers.

Torque loads are a function of the pump differential pressure, efficiency of the pump, the pump internal friction, and a resistive torque of the fluid between the rod/couplings and tubing.

Torque Load
The total torque can be expressed as:


Where:

Tpumpfriction is the torque required to overcome the fit between the stator and rotor and allow the pump to turn. The value is typically 65-100 ft.lbs and is known form experience rather than a direct calculation. In the case of a swollen elastomer this value be much higher

Tpumphydraulic is due to the work that the pump does and is calculated from:


where
Q = flowrate (bbl/day)
dP = Pump differential pressure (psi)

Tresistive is the torque required to overcome friction of the rod string rotating in the produced fluid and is calculated from:


where

In order to perform this calculation properly it should be performed using the total length of rod section, total length of couplings and total length of centralisers installed and the Tresistive for each added to give the total

The downhole torque required to turn the pump is quoted by some manufacturers in terms of HP. The following equation can be used to covert between torque and Hp for a given RPM

where:

HP = Horsepower
T = Torque ft-lbs

Axial Load
The axial forces in the rod can be calculated from

where:

and:


Rod Effective Stress
The combined loading of torque and axial load on the rod string can be accounted for using Von Mises stress equation. Calculation the torque and axial loads are best performed using software although there are a number of equations and tables that can be used to estimate the forces and calculate the effective stress on the rod. In order to ensure a safety factor an effective stress of less that 70-80% of maximum is used.


Rod Types
Normal sucker pump rods can be used to power the PCP but a number of companies now make Drive rods specifically for a PCP application. The following picture compares a 1" drive rod (upper) with a 1" sucker rod (lower)

Drive rods have the following advantages:

• Smaller coupling (less requirement for axial strength) which reduces tubing wear and flow losses
• Smaller upset so more resistant to fatigue
• Thread designed for higher torque resistance

Correct Make-Up
Regardless of the type of rod used the coupling should have higher stress capacity than the body of the rods and yet when rod failures are sustained, they are typically in the coupling rather than the body of the rod. In order to avoid failures of the coupling it is critical to ensure correct make-up of the coupling. The key steps to successful make-up are:

1. Apply manufacturers recommendations (may differ by supplier)
2. The sucker rod specification API RP 11BR is not adequate for PCPs.
3. Ensure the coupling faces and rod shoulders are clean and free of grease.
4. Use the lubricant recommended by the manufacturer.
5. Only lubricate the pin, lightly.
6. Use torque make-up (JAM unit) rather than rotary displacement to ensure correct make-up (Note: if using rotary make up cards, the card will most likely be different from rod pump applications).
7. Every connection (both ends) needs to be subjected to correct make-up procedure and torque.
8. The make-up torque of the rods should be higher than the expected operating torque.

Continuous rod is available (co-rod) which is like coiled tubing only solid. Co- rod only requires a coupling at the top and the bottom of the rod string and so is more suited to deviated wells, causes less tubing wear and eliminates the potential for coupling failures.

Other concerns
Consideration must also be given to the fact that the top of the rotor is moving eccentrically, as such the connection and first 30ft of rod above the rotor needs to be designed to accommodate such movement. It is recommended that a full sized sucker rod be used at exit but at least a pony rod no shorter than 8'. Also do not swage down to a smaller flow passage for 4' (from Weatherford).

In directional wells centralisers are often used to centralise the rod string and prevent rod and tubing wear. Spacing of centralisers is based on the profile of the wellbore.

Drive system
The drive system is normally comprised of a drive head, speed reducer and a power source. The function of the drive system is to:

• suspend the rod and carry axial loads
• deliver torque to the rod
• rotate the polished rod at desired RPM
• prevent backspin
• prevent escape of produced fluid

Various drivehead configurations are available that allow the drivehead to be vertically or horizontally. Typical HP is in the range of 10 - 100 HP.

Speed reducers are available that facilitate either fixed speed or variable speed drives. Variable speed drives allow for more well inflow uncertainty.

Prime movers can be electric motors, hydraulic motors or internal combustion engines. Electric motors are more efficient but require the wellsite to have electricity, although solar power can be used in some applications.

The required power output of the prime mover can be calculated from:

Where:

PCP Design
The basic procedure for pump design is as follows:

1. Assume a design flowrate (STB/day), watercut, wellhead pressure, pump setting depth and reservoir inflow performance
2. Calculate bottomhole flowing pressure for desired flowrate
3. Calculate required intake pressure at pump depth
4. Calculate pump discharge pressure (wellhead pressure + gravitational pressure loss + frictional loss).
5. Calculate pump differential pressure and convert to head by dividing by fluid gradient of produced fluid. To this point the design is what is also required for and ESP design when the TDH is calculated.
6. Examine pump specifications and curves, select appropriate pump to produce desired flowrate with RPM of less than 300 and expected pump differential of approximately 70% of pump maximum.
7. Calculate required surface torque
8. Calculate forces in rod string for expected operating conditions, size rod string appropriately to ensure that rod string is adequate for loads (less than 70-80% effective stress).
9. Calculate HP requirement of drive head and bearing rating for axial load.
10. Determine power generation requirement

Operation, Monitoring and Diagnosis
A typical monitoring system will include torque and RPM sensors to measure the mechanical system response. The majority of PCPs are applied in low cost operating areas and an operator is often reluctant to spend additional capital on equipment for monitoring of the PCP system.

Advanced monitoring systems will include a downhole sensor to measure pump intake and discharge pressures, pump discharge temperature and vibration. A controller can then be used in conjunction with a variable speed drive and remote diagnostic software to optimise well production within the system limits of rpm, torque and pump depth relative to fluid level.

The following table provides a summary of the measurements that can be taken:


The efficiency is the ratio of the power to lift fluids from approximately the fluid level in the casing divided by the input power to the system.

One simple monitoring process can be the pump efficiency. The formula is:

The simple formula showing what the production is as a % of the no-slip production is a method of estimating if the pump is too tight or too loose. If the efficiency is over 90% field experience should be monitored to see if pump is too tight to restart or breaks in the pump or rods occur. If the n is lower than -80% then experience may show the pump is set too loose in the shop and after the pump elastomer swells in field operation. It is one way to try to monitor performance without additional instrumentation.

The following graph (figure 5) shows a plot of pump operating parameters acquired during a PCP start-up.


Figure 5 - Typical data during PCP start-up

It can be observed that as pump RPM increases torque, discharge pressure and discharge temperature increase significantly. Conventional wisdom would say higher RPM means higher flow which means greater frictional pressure drop in the tubing resulting in an increased discharged pressure (discharge temperature increases as a result of increased heating in the PCP). However, consideration of the wellhead pressure trend shows that a large proportion of the pressure increase at the pump discharge is due to the increased wellhead pressure (due to increased pressure drop in the horizontal surface pipeline or pressure drop across the surface choke). This plot indicates the importance of considering the hydraulic parameters (pressure) as well as the mechanical measurements (torque and RPM) to understand the response of the system.

Through the use of measured downhole parameters it is possible to determine:

• pump performance
• fluid loss / slippage
• tubing frictional pressure drop
• torque due to pump
• well inflow information for pump redesign

Common operational problems that can be diagnosed using a combination of surface data and measured downhole parameters are:

• pump wear
• excess pump friction (stator swelling)
• plugged pump intake
• pump off
• tubing leak
• excessive gas at pump intake
• sand loading
• parted rods

Production Optimisation
The key to production optimisation is to reduce the bottomhole pressure (Pwf), create more drawdown (Pr - Pwf ) and allow the well to flow at a higher rate. Increasing the RPM for a PCP results in reduction of Pwf.

Traditional analysis methods have used 'Echometers' to infer the fluid level. A more advanced method is to use a downhole pressure sensor and measure the actual pressure. A direct measurement of the pump intake pressure is the most accurate method to determine whether there is an opportunity to produce at higher rates by drawing down the Pwf further (note it is also necessary to monitor casing pressure in conjunction with intake pressure).

Another system used with good success is to use the OGI system with a flow measuring system in the flowline (good for water, perhaps not for heavy viscous oil) and when rates drop, a VSD is signalled to slow the unit. A complete system of control algorithms are available with the system. No downhole sensors are needed.

A downhole pressure sensor can be used to monitor well pressure when the well is shut in (build-up) and provide an indication of reservoir pressure but downhole sensors are more prone to fail.

Automation
Automation provides the best means of optimising production whilst preventing equipment failure. The technology exists to automate the PCP system as follows:


Alternative Deployment
As an alternative to powering the PCP using a rod string and drivehead it is also possible to use a downhole (ESP) motor to power the PCP.

In order to drive the PCP using a downhole motor it is necessary to use a gear reducer (9:1 or 11.5:1) to run the PCP at an acceptable speed (100 to 500 RPM).

This type of system has the following advantages over conventionally deployed PCPs:

• Can be set deeper
• Better suited to horizontal or directional wells
• Reduces frictional pressure drop in the tubing
• Eliminates potential for tubing wear

Some of these systems are designed such that the PC Pump can be moved and reinstalled using wireline or coil tubing while leaving the motor in the hole.

Labels: gas, installation, oil, optimisation, PCP, Progressive Cavity Pumps, Russia

posted by The Rogtec Team @ 15:34  0 Comments

Underreaming of wells brings extraction benefits but places heavy demands on casing centralisers. Cliff Berry, Sales and Marketing Manger at Centek Limited, discusses some of the issues.

Underreaming is a widely used drilling technique for enlarging the diameter of a borehole at some point below the surface. Underreamed sections are generally drilled in order to maximise the size of tubular that you can put down. A conventional well is drilled in a telescopic fashion, but as you telescope down you end up being limited by the final casing size, which can be as small as five or six inches.

An important benefit of underreaming is it improves the flow and pressure of the annular fluids, but by increasing the fluid flow you run the risk of eroding the surrounding formation as the fluid usually has drilling particles in it and is highly abrasive. You are also often limited to how central you can get the pipe, which depends on the borehole shape. If you can increase the diameter of the annulus you improve the potential for cleaning out on the narrow side, so if a pipe is sitting to one side having a bigger annulus should help increase the flow without risk of damage to the formation.

A fundamental problem with underreamed wells is getting effective casing centralisation in the underreamed section. Ordinary bow-spring centralisers can be damaged when passing through previously set casing. In order to try and ensure centralisers are not damaged once in the underream, some suppliers make them oversize so as to improve stand-off down hole, but this results in a new penalty as the tightness of these centralisers in the casing requires a huge prestart force to get them moving. Modern wells are highly complex in profile and run to ever increasing lengths. The preload of an oversize bow-spring centralizer results in an accumulative resistance that can prevent passage of the tubular to final depth.

In addition, conventional bow-spring centralisers that are wide enough to fit the underreamed section with any accuracy often get damaged when they have to pass though narrower casings. The bows get compressed to such an extent that they lose their elasticity and can't expand to the correct diameter of the underreamed hole - a condition known as permanent set. Ordinary bow-spring centralisers, while perfectly adequate in straightforward applications, are not designed to be severely compressed and passed down thousands of feet of smaller bore pipe for hours, to then emerge and expand to their design diameter in the under-reamed hole.

All of this gave bowspring centralisers a bad name in the more arduous applications. As a result the industry veered towards strength before all. The strength before all solution to the underreamed centraliser problem is the solid or rigid centraliser. Produced from a piece of solid steel, zinc, aluminium or plastic, they are certainly strong, though often brittle, and completely inflexible. The solid centraliser has a problem when it emerges into the underreamed section, because with its fixed diameter it is undersized for the previously set casing let alone the underreamed hole. This is exacerbated in highly-deviated underreamed wells, as in the open hole the centraliser is too small to provide effective centralisation, and will lie on the low side producing a much less effective cement job than does a well fitting bowspring designed for the purpose.

This leaves the drilling engineer with an unsatisfactory dilemma between centraliser failure and inadequate cementation. Devon-based Centek believes it has the answer in its family of bow-spring centralisers that combine flexibility with unparalleled strength.

Centek centralisers are manufactured from a single piece of steel which is fully heat-treated to give a hardened surface that results in greatly reduced torque and drag losses, so abrasive wear caused by running to depth and rotating the tubular is virtually eliminated. These centralisers offer exceptionally high fatigue strength for axial forces and radial side loads on bows during tubular rotation.

Despite being fully compressed during passage through the casings, the centraliser offers exceptional restoring force with a very high stand-off ratio once in the open hole. As a low profile unit it takes up less annular space, so its ECD (Equivalent Circulating Density) signature is low allowing the operator if required to pump at a slightly higher rate. This improves well cleaning, and the low torque aids part rotation and minimises stall-out all of which contribute to improved cementation.

The Centek S2 UR centraliser is oversized for the casing it has to pass through, but despite this it requires only a low start force and running force once the unit has been inserted into the previous casing, and it is robust enough to withstand compression when passing through the casings. Typically it can pass through the internal diameter of a 95/8 pipe (approximately 8½ inches) to pop out and expand to a 9½ inch underream. If drilling is carried out with an 8½ inch bit and then underreaming to 9½, 10 or even 11 inches, Centek can produce a centraliser that will compress and then expand to fit the largest hole the customer requires, within reason. Underreamed centralisers are not manufactured to API standards as there is no API standard for underreamed applications.

Centek’s range of under-reamed products have been used successfully in thousands of applications worldwide without a single centraliser failure. Instances where tubulars have had to be pulled out of the borehole for reasons unrelated to centraliser performance, have revealed Centek centralisers in full working order and suitable for re-running. These overall results and design strengths have allowed Centek to successfully challenge the view that bow spring centralisers should not be used in extended reach or highly deviated wells - you just need to ensure the correct bow spring is specified. In an underreamed hole, the Centek S2 UR gives a better likelihood of cementing a tubular in place and getting the optimum amount of cement around it.

Labels: Centek, Centraliser, gas, oil, Russia, Underreaming

posted by The Rogtec Team @ 12:38  0 Comments

Introduction

Possibly the single biggest investment of funds that will be made during the lifecycle of a hydrocarbon asset is that in the design, procurement and construction of the surface and sub-surface facilities to produce the resource. Yet, within the upstream industry we hear very much more about unsuccessful projects than we do about success in projects. Realistically there are many projects that ultimately meet the business objectives that generated them, and that in itself is a form of success. However, it does not necessarily mean that the capital project in itself has been a success.

The argument of this paper is that upstream companies need to create the environment within their business structure and processes to motivate and manage success in projects, or at the very least to recognise and acknowledge the context of the capital project in the overall business plans for the asset. This will contribute to the generation and realisation of value through the project, and also to safeguard against loss of value.

What is a Successful Project?

The definition of a successful project is one of those nebulous concepts that tax the minds of everyone in the industry. Success in a project is usually in the eye of the beholder, and there are many stakeholders in that success, often with competing ambitions. A very simple definition of the successful project outcome, and one that has served well over recent years is:

"a project that meets the quality, scope and business targets of the stakeholders, and does so within agreed budget and time constraints whilst complying with corporate, local and national Health, Safety and Environmental principles" (see fig.1)

That is perhaps simple to say, but not so simple to achieve, especially in view of the complex nature of the composition of stakeholders today. Such stakeholders might include shareholders, joint venture partners, executive management, national governments, local populations, customers of the resource, and not least, the project and asset team. It is therefore, vitally important to create a business process landscape within the

Figure 1 The Successful Project



Operator company that can manage all aspects of creating stakeholder success, and ensure that the expectations of all stakeholders are taken into account in the planning and execution of the project.

National and International Oil Company Perceptions of Project Success

National Oil Companies (NOC's) will very often take a different view of project success criteria than International Oil Companies (IOC's), sometimes now referred to by NOC's as International Investor Companies (IIC's). However, both are stewards on behalf of the stakeholders in their companies of funds invested. Most IOC's are answerable to their investor stockholders for the manner in which they invest capital funds, and the efficiency with which they deploy such funds. NOC's are normally answerable to their major governmental investors on behalf of their citizens, to a greater or lesser extent. Thus NOC's and IOC's share at least some common ground on project success, and in many cases, where they are in a joint venture, each must consider the success criteria of the other.

The Process Landscape

Consideration of expectations in respect of the outcome of both the business and project targets and objectives must begin early. In many upstream companies, both national and international, this is hampered by a lack of focus on the integrated nature of the processes that drive the business. In recent years, however, many of the larger international companies have moved towards the identification of their key processes, and structuring the achievement of their business targets around those processes. This has opened up the possibility for integrating the capital project into business planning at a very early stage, and especially in managing the project risks and uncertainties from that early stage.

We should begin with the process landscape. During the 80's and early 90's, many companies began to realise that there was much redundancy and confusion in the many processes they deployed to run their businesses. This drove the need for central hierarchical manpower driven structures to manage the business, rather than more efficient and better

Figure 2 Upstream Process Landscape




focussed devolved asset based organisations. Gradually the focus turned to the latter. The first objective was not necessarily to get rid of processes, rather to define and prioritise them. A typical current landscape model encompasses three process categories (see fig 2):

Core Process, which describe the main engines of driving the upstream asset business delivery through its lifecycle, and include

• Explore
• Appraise
• Develop (including the Capital Investment Project)
• Produce
• De-commission/Remove

Management Processes, which, inter alia, set out the overall business targets, manage the portfolio, define where core processes will be deployed, set out business policy/ethics

Enabler or Support Processes, which provide the essential technical, commercial, and marketing support to both the Core and Management Processes.

So, whilst it is generally acknowledged in the industry that capital projects will have to be entered into at some stage in order to realise the value of the resource, whether in fact or notionally (as in the case of asset trades, acquisitions etc.), the Process Landscape provides an insight for the first time to many as to the context, and where the Project fits into the asset lifecycle. But more importantly, it provides an opportunity to bring structure to the Develop process, and to begin to manage project expectations and success criteria at an early stage for all stakeholders.

The Development Process and Project

With the establishment of a Core Process driven business, it is now possible to drill down into each of those processes and to identify sub-processes that will support and enhance the objectives to the process itself.

Again a typical set of sub-processes for Develop and its projects could include (see fig 3):

Figure 3 Phases of the Capital Development Project




A typical set of sub-processes for Develop and its projects could include (see fig 3 above):

Concept
to answer the question whether there are technical solutions that will meet the business objective(s)
Feasibility
To identify which of those technical solutions is most appropriate to meeting the business objective(s) in terms of value, risk/uncertainty management, flexibility
Definition
To define the selected concept and engineer it to a point where the definition of cost, schedule and quality/scope/business targets meets agreed criteria for a Final Investment Decision (FID).
Execution
The phase of major investment in design, procurement, construction and bringing into production of the surface and sub-surface facilities


The structure described enables the establishment of a defined set of targets, activities and deliverables from each phase in accordance with the policies procedures and guidelines for the Develop process and its projects. The development of such policies, procedures and guidelines will be facilitated by the clarity of process focus provided by the structure. They would be contained within, for example, documents such as Project Management Procedures and Guidelines.

Phase Gates for Control of Projects

The phased approach described above provides an opportunity for the establishment of decision gates at the end of each project phase. Each gate will progressively address and help to mitigate outstanding risk and uncertainty from all sources, until at FID the stakeholders will have a very clear picture of how the work to date has been carried out, and what residual risk/uncertainty remains. In that manner, their expectations can be aligned, or at least they can agree to differ, or to add in the contingencies.

It should be noted that some companies have adopted the gate process as a management tool within their management processes. In many cases, they apply it not only to capital development projects, but also to activities in other core processes such as Explore and Appraise. Again, this generates a greater degree of understanding and confidence across the whole business on what is expected at the executive level in order to obtain approval to make an investment. The basis of the targets set will be contained within the guidelines and procedures established for each process.

Benefits of the Structured Approach to Projects

To begin with, it is often argues, especially by small upstream companies, that an excess of structure and protocol introduces too much inflexibility to their methods of doing business, especially when they claim that their developments are "simple". This may be valid in some cases, but in most cases there are no "simple projects" in the upstream industry. Some degree of process and focus is to be recommended, especially with small entrepreneurial companies that could be destroyed financially by a failed project.

However, there are many benefits to be gained from the adopting the structure and processes outlined above in managing the success of capital projects. These include:

1. Provides a common template across the company in all of its locations as to what is expected by the executive and stakeholders in respect of the investment in the capital project

2. Generates alignment with corporate decision making processes not only within the operator company, but also with joint venture partners and other stakeholders.

3. Generates alignment of the objectives and expectations of the executive, the asset and the project.

4. Facilitates the establishment of standards, procedures and guidelines for the conduct of development projects, and the means to determine targets and deliverables.

5. Facilitates the establishment of common definitions of roles, responsibilities, authorities and accountabilities.

6. Promotes Management by Objectives.

7. Provides a structured and consistent basis within which to incorporate best international practice into the planning and execution of capital projects

8. Provides a consistent environment within which to identify the skills and competencies necessary to achieve a successful project outcome at all phases of the project

9. Supports a structure that promotes multi-discipline teamwork and communication to meet common targets and objectives

10. Provides a vehicle for identifying and managing risk and uncertainty on the project, thus avoiding misunderstanding on stakeholder expectations

11. Provides the environment within which each process and sub-process may be resolved into its component units, thus identifying and defining inputs, roles and responsibilities essential to achieving desired outputs.

12. Supports the definition of principles for devolution of authority to the project and asset team commensurate with the perceived need and residual risk/uncertainty.

Conclusion

In conclusion it may be argued that, if upstream companies wish to achieve success in their capital projects, and reap the value rewards that they will bring, they should look very closely at their business structure and processes, and ensure that they represent an environment that will support and promote project success, however it may defined.

By Thomas Harding, Devcor Studies LTD & Mick Small, RPS Group

Labels: Capital project success, gas, Group, Mick Small, oil, RPS Energy, Russia

posted by The Rogtec Team @ 15:36  0 Comments