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By: J F Lea, PLTech LLC, David L. Divine, P.E. Wood Group ESP, & Lynn Rowlan, Echometer Co.

Introduction:
The electrical submersible pump system has been developed over the years by Engineers and scientists involved in metallurgy, hydraulics, electronics, heat transfer, plastics, many aspects of mechanical engineering, and other disciplines. It is not practical to outline all of the many aspects of the system in the short introduction section. Instead, the major components are introduced.



Overview:
The pump assembly is hung on the tubing with the electric cable banded to the outside of the tubing from surface to pump. The equipment is arranged from top to bottom with the pump first, with the gas separator below, then the seal section, followed by the motor. If a downhole pressure sensor is used, it is hung at the bottom of the motor. ESP's are thought of as high volume lift perhaps producing -20,000 bpd at 4000' down to -5000 bpd at 10,000' depending on many factors, but low volume (-100 bpd) stages exist.

Motor:
The electric submersible motor is a two-pole, three-phase, squirrel cage induction type. The motor runs at a nominal speed of 3500 rpm on 60 Hz frequency and 2900 rpm on 50 Hz. The motor is filled with a refined mineral oil to provide dielectric strength, lubrication of bearings and thermal conductivity. The thrust bearing of the motor carries the load of the rotors. The electrically nonconductive mineral oil lubricates the motor bearings and transfers heat in the motor to the motor housing. Heat from the motor housing is in turn carried away by the well fluids moving past the exterior surface of the motor. For this reason, the motor should not be set below the point of fluid entry unless some means of directing the fluid by the motor is utilized. Typical nominal motor diameters of equipment may be: (a) 3.75", (b) 4.56", (c) 5.402, 5.44", 5.62", and (d) 7.38" for various casing sizes. Some motors are offered with somewhat different diameters and some manufacturers do not carry some of the diameters indicated. Some Motor construction may be a single housing or several "tandems" bolted together to reach a desired horsepower rating. Motors range in horsepower from 5 to 1000 hp and larger.

Pump:
The electric submersible pump is a multistage centrifugal type. The type of stage used determines the approximate design volume rate of fluid produced but as the fluid compresses, each stage will have progressively less volume to handle. The number of stages determines the total head designed for and the motor horsepower required.

The usual materials used in manufacturing an impeller are Ni-Resist with some options for sand handling. Diffusers are typically manufactured of Ni-Resist. The standard shaft material is K-monel. Optional, high-strength shaft materials are Inconel and Hastalloy. Bolt-on heads and bases make it possible to vary the capacity and total head of a pump by using more than one pump section. However, large capacity pumps typically will have integral heads and bases. The nominal outside diameter of a pump will range from 3.38" to 11.25" but 7.62" to 8.38" could be largest oil well applications.

Seal Section. Protector, Equalizer:
The motor protector's primary purpose is to isolate the motor from the well fluid. There are, in general, two types of industry protector or seal section designs although there are specific differences from one brand to another. One type uses a positive bag seal and the other type uses a labyrinth or tortuous path. The "positive seal" design incorporates a fluid barrier bag to allow for thermal expansion of the motor fluid yet still provided isolation of motor fluids from wellbore fluids. The "labyrinth path" utilizes differential fluid specific gravity to prevent well fluid from entering the motor. This is accomplished by paths where the motor fluid is allowed to expand to displace more or less of the wellbore fluid as it expands through a tortuous path at an interface near the top of the protector. There are usually several "labyrinth paths" in one protector and more could be added by placing protectors in series. Normally the bag type positive seal protector is backed up with "labyrinth paths" so that bag failure is not necessarily catastrophic.

The protector or seal section performs four basic functions. These are: (1) It connects the pump to the motor by connecting the housing and drive shaft; (2) Houses a thrust bearing to absorb pump shaft thrust (if present); (3) Isolates the well fluid from the motor while still allowing pressure equalization between the wellbore and the oil-filled motor; and (4) provides for thermal expansion of the motor oil due to heat generated by the motor during operation and thermal contraction of the motor oil following pump shutdown/startup.

Gas Separator:
The gas separator is installed between the protector or seal section and the pump. Its purpose is to separate a significant portion of any free gas in the produced fluid and provide a fluid intake section for the pump.

There are two major types of gas separator designs - the static type and the rotary type. The static type reverses the fluid flow direction within the housing but the use is not as frequent now. At this point of low pressure there is gas separation. Any gas remaining in the fluid is separated by the pickup impeller which causes a vortex. The vortex allows the gas and fluid to separate. The separated gas is vented to the annulus and the higher density fluid flows into the first stage of the pump.

The rotary type design utilizes a rotary inducer/centrifuge to centrifugally separate the gas and produced liquids. The gas/fluid mixture initially enters the intake ports and moves into the inducer. This increases the pressure of the fluid and moves it through the transition section into the centrifuge. In the centrifuge the fluid is forced to the outside and gas rises through the centrifuge and flow divider into the crossover section. Here, the gas vented into the annulus and fluid is directed into the first pump stage. At present three (four in the near future) manufacturers are producing this type of separator. A "Vortex" separator may have a smaller paddle wheel at the bottom of a chamber where gas and fluids can swirl before exiting the separator.

Special stages are offered by some manufacturers when there is no path for separated gas. The special stages mix the gas and fluids and some are more proficient in producing head in the presence of high gas content.

Pressure Sensing Instrument:
The instrument has two major components - a surface readout unit and a downhole pressure and temperature sensing instrument. The downhole sensor is bolted to the base of the motor and sends a "ghost" signal to the surface unit through the motor windings and power cable as opposed to older designs requiring an extra "I" wire. One readout instrument alternates pressure and temperature readings on a 20-second interval. Other downhole instruments including intake and motor winding temperature. Other types of instrumentation are available.

There are many factors involved in operating ESP systems to lift a field. Below is an outline covering many of the aspects to be aware of when operating ESP's.

Outline of Factors for Good ESP Operations:

1) Well Data for Design and Operation:
i) Well tests
ii) IPR data
iii) Temperature and fluid properties
iv) Harsh conditions present?
(a) Sand
(b) Scale
(c) H2S, CO2
(d) Viscosity, emulsion
(e) High Temperature
(f) High gas production with the liquids
(g) Deviation
(h) Other?
v) Well Profile
vi) Tubulars
vii) WHP
viii) HZ of power supply available
ix) VSD part of installation?

2) Select Target Production:
i) AOF of well
ii) Bubble point
iii) Produce above or below bubble point
iv) Target production

3) Equipment Design:
i) Determine TDH
ii) Select type of pump and calculate number of stages
iii) Intake: Standard or gas separator
iv) Protector/Seal/Equalizer
(a) Bag/s
(b) Labyrinth sections (*)
(c) Tandem protectors?
v) Motor, type, HP
vi) Downhole instrumentation
vii) Cable: round / flat, size
Bands or cross coupling protectors
viii) Well head feed through type
ix) Control panel: Standard or VSD
x) See API RP 11S4 Recommended Practice for Sizing & Selection of ESP Installations

Example Simple Conceptual Design:

Consider the following data for design purposes. More detailed data would be required for actual application design:

IPR:
SIBHP: 2900 psi
Test Rate: 4000 bpd
Test Pressure on Perforations: 400 psi

Little gas
Perforations Depth: 6500 ft
Pump Depth 6000 ft
Casing: 5.5 inch
Tubing (to be determined but for 4000 bpd should be 3 ½, 4 or 4 ½ inch approximately)
WHP: 100 psi

Consider combination of water and oil such that the combined SpGr is 0.9. Approximate using volume of liquids do not change with down hole pressure and temperature. This is not true of course but approximately true if high water cut and little gas. This assumption allows a simple design example. For more and more gas and oil with water, this would be less and less true.

Power supply is 60 HZ. Use the above pump performance curve for this example.

Target rate: 4000 bpd

The pressure at the perforations is 400 psi. Consider the casing flow to the pump intake has little friction.

The pump intake pressure, PIP, is 400 psi – 500 ft ( .9*.433 psi/ft) = 205.15 psi.
For tubing flow to calculate the discharge pressure, consider tubing is selected such that friction pressure is 2-5% of the tubing pressure drop. This is typical for design of ESP. For this design use 3% for friction pressure drop.

Discharge pressure = WHP + .433(.9)(Depth)(1.+ % Friction) =
= 100 + .433(.9)(6000)(1. + .03) = 2508.3 psi

Then the TDH or total dynamic head is : TDH = (Pd – PIP)/( (.433)(.9))
= (2508.3-205.15) / ( (.433)(.9)) = 5901 ft

From the above performance curve read about 43.5 ft / stage.

Then the number of stages required is:
* Stages = TDH/ (head/stage) = 5901/43.5 = 136 stages

The HP required from the motor would be:

(* Stages) ( HP/Stage) (SpGr) = 136(1.95)(.9) = 238.7 HP
A larger somewhat de-rated motor would normally be selected for application



To complete the design, a cable would be selected (normally with no more that 30 V/1000 ft voltage drop), a switch board or VSD would be selected, and use of tubing for this design should be such that the pressure drop due to friction would be about 3% of the total tubing pressure drop. Other hardware would be ordered.

For heavy oil viscosity correction factors would come into play. For free gas at the pump intake, the gas would become part of the volume digested by the pump and the gas would also reduce the effective SpGr of the mixture. For more than 10-15% at the pump intake, we would become more concerned with the need for gas separation.

VFD or Variable Drives:
For critical installations, many times the data is such that the design may not fit the well conditions as the operator would prefer. Also changing well conditions may require changes in the ESP operation before the unit is pulled. If sufficient motor capacity is available, then a VSD can help achieve optimum operating conditions before the unit is pulled.


Variable frequency drive (VFD) controllers are solid state electronic power conversion devices. AC input power is first converted to DC intermediate power using a diode rectifier and/or thyristor (SCR) bridge. The DC intermediate power is then converted to quasi-sinusoidal AC power using an inverter switching circuit. [1] Figure 1 is a basic block diagram of a VFD connected to a motor.



For the electrical submersible pump (ESP) application there is a step up transformer and a length of cable between the output of the VFD and the motor.

VFD's for ESP oil well applications are divided into two major categories. They are either variable voltage inverters (VVI) or constant voltage inverters (CVI).

AC motor characteristics require the applied voltage to be proportionally adjusted whenever the frequency is changed in order to deliver the rated torque. For example, if a motor is designed to operate at 460 volts at 60 Hz, the applied voltage must be reduced to 230 volts when the frequency is reduced to 30 Hz. Thus the ratio of volts per hertz must be regulated to a constant value (460/60 = 7.67 V/Hz in this case). For optimum performance, some further voltage adjustment may be necessary, but nominally constant volts per hertz is the general rule. This ratio can be changed in order to change the torque delivered by the motor. The VVI VFD controls the output voltage by controlling the DC voltage level with SCRs. The output of this type of drive is a quasi-sinusoidal wave called a 6 step shown below in Figure 2.



The vertical distance from the top of the top step to the bottom of the bottom step equals the DC bus voltage. As the frequency increases the SCRs on the input will cause the bus voltage increase and conversely when the frequency decreases the SCRs will reduce the bus voltage.

VVI VFDs with 6 step outputs have been applied to ESP oil well applications for over 30 years. There is some additional motor heating associated with the use of 6 step because on the harmonic content of the quasi-sinusoidal wave shape. This additional heating as been compensated for by using motors that have be re-rated for the application of 6-step VFDs.

The CVI VFD controls the output voltage and frequency with a pulse width modulated (PWM) output shown in figure 3 below.



The peak between the top of the positive pulses and the bottom of the negative pulses always stays the same (or constant voltage). The width (or duty cycle) of each individual pulse increases with increasing frequency therefore increasing the average applied voltage. This voltage and frequency control is shown in Figure 4 below. The average voltage over the low frequency period will be lower than the average voltage over the higher frequency period.



When the CVI VFDs are applied to the ESP oil well application, the rapid switching of the PWM output causes reflections to occur over the long lengths of power cable. This can cause voltage spikes up twice the peak system voltage to appear at the output of the step up transformer and the ESP motor terminals. Figure 5 shows the ringing that occurs at the end of the voltage transitions during the PWM switching.



To reduce the risk of insulation failure and to reduce motor heating due to harmonics the manufactures of these drives have included low pass filters on the output of their CVI VFDs. This is filtered PWM (FPWM3) or variable sine wave generation PWM (VSG PWM4). A typical voltage output waveform of a filtered CVI VSD is shown in figure 6 below.



Variable frequency drives for ESP oil well applications range in size from 25 KVA to 2000 KVA at 480 volts to 2400/4160 volts. They can be designed for stand alone applications in the field in NEMA 3 or 4 enclosures or they can be in NEMA 1 enclosures for motor control room applications. When purchased from an ESP vendor they will come with the necessary controls for motor and VFD protection and control.

1. Campbell, Sylvester J. (1987). Solid-State AC Motor Controls. New York: Marcel Dekker, Inc. pp. 79
2. Bose, Bimal K. (1980). Adjustable Speed AC Drive Systems. New York: IEEE Press
3. Registered trademark of baker-Hughes Centrilift
4. Registered trademark of Wood Group - ESP, Inc.

4) Installation:
a) There are many factors to be considered to prepare for installation, install the cable and unit components and start up and monitor the unit. See API RP 11 S3, Recommended Practice for ESP Installations. See API RP11S5 Recommended Practice for Application of ESP Cable. See APIRP 11S6 Recommended Practice for Testing ESP Cable Systems.

5) Operation / Monitoring:
i) Monitor: Amps, surface voltage, downhole temperature and pressure starts/stops, power supply frequency

ii) Advanced
(a) Motor winding and well temperature
(b) Motor fluid dielectric strength
(c) Vibration
(d) Discharge pressure
(e) See API RP 11S Operation, Maintenance & Toubleshooting of ESP Installations

6) Removal from Well/ Inspection;
i) Remove with care
ii) Inspect as removed: Sample fluids , solids etc
iii) Collect fluid and solids samples
iv) Observe color indicating exposure to excessive heat
v) Note Vibration marks if any
vi) Any evidence of cable or pothead burns
vii) Mechanical damage if evident
viii) Package including pothead and instrumentation (without removal) to shop for teardown

7) Shop Teardown:
i) Have available historical run data and documentation
ii) Sample internal materials and fluids
iii) Search for primary cause of failure and other conditions:
(a) Wear
(b) Foreign materials
(c) Electrical transients or electrical burns
(d) Water in motor?
(e) Seal function or failure of:
1. Shaft seals
2. Bag preventer
3. Contamination of labyrinth sections
4. Wear or failure of thrust bearing
(f) Motor: Burned or contaminated
(g) See API RP 11S Recommended Practice for ESP Teardown Report
iv) Determine possible reuse of pump and motor if reconditioned and tested. See APIRP11S2 Recommended Practice for ESP Testing. See API R P11S8 Recommended Practice on ESP Vibrations. See API RP 11S7 RP on Application and Testing of ESP Seal Chamber Sections

8) Determination of failure:
i) Examine removal and teardown data and assess cause/s of failure

9) Continuous Improvement:
i) Indicate equipment that could extend run life such as sand resistant
(1) Stages/ impellers or high temperature trim or need for better checks at installation etc. Note that these recommendations my not be implemented on the new equipment going in but possibly on the following run/pull/installation.

10) Maintenance of Failure Data Base:
a) In order to show improvements with time in run life, it is necessary to have a good record of past failures and the cause of each. Only then can attention be focused on the most critical areas and only then can improvements in run life be achieved.



For additional information on a failure tracking project details see: Industry
Reliability and Failure Tracking Joint Industry Projects seek to increase ESP and PCP Run-Life By Jesus Chacin, Paul Skoczylas and Darren Worth, Rogtec, Issue 7.

Labels: deployment, electric submersible pumps, ESP, factors for successful operation, oil gas, production, Russia, Zeitecs

posted by The Rogtec Team @ 11:48  0 Comments

Ye. O. Cherkas (OJSC NK Rosneft-NTC, D. A. Antonenko and P. V. Stavinsky (OJSC NK Rosneft)

Introduction
Drilling of horizontal holes imposes special requirements on the reliability of prediction of reservoir structure and quality within a large radius from the borehole. However, the reservoir prediction tools currently available to geologists suffer, to some extent or another, from measurement errors, which inevitably leads to modeling uncertainty and increases risks associated with drilling of horizontal holes. In view of the high costs involved in horizontal drilling projects and uncertainties inherent in any model, it has become imperative to address this issue. Incorrect description of a reservoir may result in swelling of irrecoverable field development costs. In a typical geological model, four major sources of uncertainty may be identified: (1) data quality and interpretation; (2) structural and stratigraphic models; (3) geological-statistical model and its parameters; and (4) uncertainty related to equiprobable realizations. In an ideal case, uncertainty decreases as the field becomes more developed.
As regards the Vankor field, which is currently under development, the most challenging tasks from the uncertainty standpoint are as follows: (1) reducing risks associated with horizontal drilling; (2) putting together a program for detailed exploration; and (3) refining the drilling program.

This paper proposes a method for analyzing uncertainties inherent in geological models. Modeling based on this method will yield data (in the form of maps) representing the quantitative distribution of uncertainties in determining the presence of a reservoir and its properties, which must be used to evaluate potential drilling risks.

General Information about the Field
The Vankor gas and oil field is located in the Krasnoyarsk Krai. This paper deals with one of five productive reservoirs with about 390 million tonnes of original oil in place. The field was discovered in 1988 and is yet to be put into commercial production. As of this study, there were 27 wells already drilled into the reservoir of interest. The deposit is a layer-uplifted pool, and the reservoir is terrigenous.

The Vankor uplift is an isometric structure extending from the south northward. The predominant depositional environment was shallow-water (barrier-bar complex).

Method
The best criterion for assessing the overall ambiguity determining the accuracy of geological model parameters is the "validity of the oil-in-place estimate". This criterion is dependent upon the basic characteristics of the reservoir and, therefore, may serve as a measure of accuracy in constructing the model. To evaluate the validity of the reserve estimate, one must evaluate the calculation accuracy of every parameter in the calculation formula


where stands for "stock tank oil initially in place", GRV stands for "gross rock volume", N/G stands for "net-to-gross", is porosity, is oil saturation, is oil density, and is the oil shrinkage factor.

To this end, a general procedure was established for handling each parameter, namely:

1. estimating possible variations in the value of each input parameter;
2. defining the RMS deviation;
3. mapping mean values of the parameter, with fixed values assigned to individual wells and taking into account the RMS deviation in the crosshole space;
4. estimating parameter variance; and
5. mapping oil-in-place variance by multiplying out variance maps for all parameters, provided that they are independent (this condition has been introduced to simplify the estimation process).

Uncertainty Calculation Approach
The principle of accounting for uncertainties is as follows: At first, one should estimate the possible error of the measurements determining the RMS deviation. Then, this error is multiplied by a random surface whose spread of values follows a Gaussian curve with mathematical expectation equal to zero and a variance equal to unity. Finally, the result is added to the reference surface:



where is one of the surface realizations, is the reference surface, is a surface or a constant determining the RMS deviation error, and is a random surface of errors with + and - values around zero.

A characteristic feature of the error surface is the fact that errors at well points acquire zero value, to increase gradually as one moves away from the wells. Thus, the RMS deviation depends on data quality and distance to the well. This approach suffers from the drawback that the range of the error variogram is unknown. It cannot be taken as equal to the variogram ranges used in the modeling of a property of interest because of their heterogeneity. Besides, randomly modeled errors may acquire positive as well as negative values because possible scenarios lie on either side of the baseline interpretation. The variogram range is selected by the interpreter based on subjective estimates of the error variance length. If the range is excessive, the final uncertainty map is smoothed out with partial or complete loss of information. If the range is too small, one will end up with a heavily "noisy" picture.

Structural Uncertainty: Presence of Reservoir
One of the burning questions during early phases of field development is whether oil is present in field areas not covered by exploratory drilling. Analysis of uncertainties may give a feel about the degree of uncertainty in identifying the presence of oil. One of the criteria for such analysis is the position of the top of the OWC. Analysis should proceed along the following lines: (1) delineate a surface over the top of a reservoir (average value); (2) introduce an error into the average value; and (3) derive intersection contours for multiple realizations of the top of reservoir and OWC surfaces.



A set of 200 contours of the top of reservoir-OWC intersection contours has been obtained for the Vankor field. The extreme values are shown in Figure 1. It can be seen that uncertainty in the position of the OWC top, which is essentially the sum total of uncertainties in the positions of the top of reservoir and the OWC, may give rise to a serious error in oil-in-place estimates. In the Vankor field, no reservoir was present within the area marked by the solid black line in 23% of cases out of the set of multiple realizations. A well drilled into the questionable target after this work had been completed failed to reveal any presence of oil. Thus, the high likelihood of absence of oil, predicted by modeling, was corroborated by real evidence. In the course of this work, two other areas characterized by great uncertainty as regards presence of oil were identified (marked by broken lines).

Structural Uncertainty: Rock Volume
Uncertainty in the position of reservoir boundaries and contact determination contribute the error in the gross rock volume measurement. As regards the structural modeling error, its major source is the ambiguity of structural surfaces in the crosshole space. The error grows with distance from wells and is zero in their immediate vicinity.

The error in determining the position of reservoir boundaries was selected based on the quality of seismic data. For the Vankor field, it was assigned as +-15 m.

Estimation of the spread of OWC values was based on the results of well tests in target sands. The spread of values was defined as the difference between the highest and lowest OWC levels. In the case of the Vankor field, the spread of OWC values was 15 m.

In this case, selection of variogram ranges was based on seismic data pertaining to the reservoir and well spacing.

As a result, maps of potential errors in determination of the top and bottom of the reservoirs as well as OWC were produced. Within the boundaries of the field, the average spread of reservoir top and bottom positions is about 5 to 6 m. Uncertainty in OWC position approaches maximum toward the field boundary and between the two blocks of the Vankor field. The rock volume was calculated as the product of gross thickness within a cell times the cell area. Figure 2 is a map showing possible deviations of the gross rock volume from average values.


Proceeding from the results of analysis of structural uncertainties, one can draw conclusions as to the presence of oil in field areas yet to be covered by exploratory drilling. This information is useful in deciding whether additional exploration of the field is needed. Information about possible variations in reservoir boundaries and OWC levels in the presence of oil is instrumental in decision-making processes as part of the field development strategy, especially when it comes to drilling of horizontal holes.

Uncertainty in Reservoir Properties
Variances of reservoir properties are mapped as follows. The input data include zero-variance points or, in other words, correlation marks by wells. An algorithm using a continuous Gaussian distribution and predetermined variogram parameters provide the basis for constructing error surfaces for a property with a given deviation from the mean. Variogram parameters are assigned based on the depositional environment (barrier-bar features, pronounced lateral consistency of properties) and well spacing. All realizations of error surfaces for a given property are reduced to a single variance map of this property at the assigned level of deviation from the mean.

Net-to-gross Ratio
The primary sources of error in identification of pay zones in wells include the resolution of logs, accuracy of determination of reservoir quality by logging, and error in the use of critical values to identify a reservoir. In order to assess uncertainty in reservoir properties, one must first know the deviation from the mean. It is recommended to select the deviation of the net-to-gross ratio from the mean on a distribution bar chart of the model (tied to log data), because we are dealing essentially with assessment of the uncertainty inherent in the model’s volumetrics. As can be inferred from Figure 3(I) the maximum net-to-gross ratio distribution density in accordance with the model is close to the interval of 15% deviation from the mean. The deviation of the net-to-gross ratio from the mean in the crosshole space is close to 4-5%.

Porosity Ratio
The sources of porosity determination error include measurement techniques, instrument error, and subjective factors. The deviation was selected from porosity distribution based on log data in correlation with core data (Fig. 3(II). It can be seen from Figure 3(II) that the maximum density of porosity values coincides with the 0.18-0.22 interval. This spread of values corresponds to 10% deviation from mean porosity. In the crosshole space, the deviation of porosity values is 0.6%, increasing to 0.8% toward field boundaries. The map indicates areas requiring updated data.

Oil Saturation Factor
The error in determining the oil saturation factor stems from the quality of interpretation of log data, reservoir resistivity determination error, groundwater level, height above groundwater level, capillary curve, etc.

According to the model, the distribution of the oil saturation factor is at its maximum in the 0.4-0.7 interval, which corresponds to 25% deviation from the mean (Fig. 3(III)). In the crosshole space, the deviation of oil saturation from the mean is 4.5%.



Uncertainty in Oil Properties
The oil shrinkage factor and density at the surface were determined as the average of a number of analyzed samples. To take the determination error into account, distribution functions were created with due account for the results of analysis of all oil samples in surface and reservoir conditions. The distributions provided the basis for calculation of oil parameter variances.

Uncertainty in Oil-in-place Estimates
After mapping of variances of each parameter in the oil-in-place estimation formula, variances of oil-in-place estimates are mapped by multiplying out variance maps for all parameters, provided that they are independent.

A map of uncertainties inherent in the density of oil in place is shown in Figure 4. According to the map, the overall uncertainty in field reserves may amount to about 10% of original oil in place.



A set of structural maps and maps of reservoir parameters with whatever errors they contained was used to produce a set of Vankor field reserve density maps, and estimation was made of the probability density and cumulative frequency functions for oil-in-place reserves expressed in tonnes. Over a set of a hundred realizations, the spread of oil-in-place estimates is within +-10% of the mean. According to the diagram of sensitivity of oil reserves to the major estimation parameters, the most tangible impact on uncertainty in oil reserves within the bottom portions of the reservoir is produced by oil saturation, although in most cases it is the gross rock volume. This can be explained by the fact that most of uncertainty is associated with the edges of the field and the space between two of its blocks, where rocks exhibit poorer reservoir properties (see Fig. 3).

Conclusion
The proposed method for assessing the overall uncertainty inherent in oil-in-place estimates makes it possible to plan detailed exploration of the field and to refine the reservoir management plan in order to reduce the combined geological risks and, consequently, increase the profitability of the project.

Labels: drilling risk assessment, Exploration, horizontal well, Label, modeling, oil gas, reservoir, Rosneft, Russia, Vankor field

posted by The Rogtec Team @ 10:50  0 Comments

TNK-BP strategy in exploration and production is focused on application of new technology to turn the Company's huge resources into proven reserves. TNK-BP's investment into seismic should be supported by solutions ensuring secure information storage, and investment into exploration should be supported by solutions ensuring data reliability and accessibility.



Oleg Bantyukov (ONBantyukov@tnk-bp.com), Data Quality Improvement Section Head, IT and Database Dept., TNNC


Pavel Potapov (PAPotapov@tnk-bp.com), Acting Head of Archive Systems Section, IT and Database Dept., TNNC

Data Management Organization of Tyumen Petroleum Research Center (TNNC) is in charge of developing a quality data management system in TNK-BP (see "Data Management: the Future is Defined by the Newly Established Organization", Innovator 20). Today, it manages all exploration and production data flows within the Company and supports all TNK-BP's Performance and Business Units. The Organization provides over 40 various services on corporate exploration and geological and geophysical (G&G) databases and archives to users from all subdivisions of the Company.

Creating TNK-BP Seismic Archive
One of the priority tasks for the TNNC data management specialists is to develop a corporate seismic archive.

The seismic data is currently stored in IT and Database Dept., TNNC, on a specially allocated 500 GB disc array, as well as in PCMS seismic data management system. However these recourses are not sufficient, and up to 75 percent of the information is stored on single-copy magnetic tapes. In standard conditions, these records loose their properties after five to seven years of storage. Thus, in several years the Company may loose up to 25 percent of the acquired seismic data if it does not provide the right storage conditions.

Moreover, data volume increase, random data storage on multiple media, data duplicating and lack of a consolidated corporate storage system hampers efficient work with the information and creates additional risk of data loss. These all dictated the necessity to develop a comprehensive shared information system to manage the seismic data and store primary seismic information and the results of its interpretation.

Over the last two years, TNNC has made major efforts to create and equip the Company's seismic archive which is to start working in 2009. In summer 2008, a core storage facility was commissioned; it is now being equipped - racks have been purchased to store the seismic data storage media (Fig. 1), their installation is planned for the next spring. Furthermore, terms of reference have been developed and approved to create an indexing system for the seismic data storage media. It is planned to begin its installation in December 2008. After that, the storage media will be marked and indexed. The system will provide for the opportunity to identify the location of the required data in 3D mode showing the numbers of the room and the shelf.



In January, a hardware and software complex will be shipped from Finland which will help expand the disc space for data storage and provide backup. In 2009, it is planned to equip the seismic data storage with a ventilation and humidification system to ensure reliable and longterm media storage, complete the data indexation, and arrange a centralized system for initial seismic data storage media search and complete the media bar-coding.

Data Quality Means Operations Quality
Another priority in data management is to ensure the quality of the G&G data. The lack of appropriate processes in the Company's PUs impacted data quality and integrity, as well as delayed its download into the Corporate Database (CDB). The inconsistence of information flows caused massive duplication both for the initial information and the interpretation results which resulted in the need for sidetracking and pilot drilling as well as causing unjustified expanses of the Company.



Data quality and integrity is negatively affected by the fact that PU specialists do not have a tool to check and visualize operational G&G data coming from the contractors. That is why the key objective for TNNC Data Management Organization in this field is to develop tools and software to control the quality and reliability of the information downloaded into the CDB. Data Quality Improvement Section within TNNC IT and Database Dept. is in charge of this work.

The Section initiated the development of software to convert unstructured G&G and exploration and production data into the Company's standard format and provided it to the contractors in geophysical studies. For the first time ever, the Company has developed regulations for the submitted data and the tools to convert the data into the desired format.

Thus, File Inkl View includes a standard algorithm to calculate directional survey parameters based on tool-measured parameters, such as depth, angle and azimuth; average angle method is used to calculate trajectory. VDL (variable density log) Converter is used to convert unstructured files containing cementing quality findings into structured WDEF files. Another tool, PGIS (Development Logging) Converter, converts unstructured files containing well log control findings into structured WDEF files. Templates for the created files are generated based on appropriate Corporate Technical Standards.

An effective tool was developed for PU specialists to evaluate input data quality based on certain criteria and visualize the acquired data in 3D mode.

File Inkl View is designed for directional survey data (Fig. 2). When analyzing the well data, the user can easily change the borehole image scale and dimensional orientation to view the trajectory from all sides. The software provides for batch control of structured files, and the quality of the provided geophysical data is assessed within minutes. FileTest is used to process structured text files containing well data in LAS (Log ASCII Standard) format, ver. 1.2, 2.0 and 3.0. PGIS Test checks the structured WDEF files containing well log data for certain types of errors, the list of which will be further expanded. Another tool, VDL Test, is used to menting quality findings. It helps identify gross errors in cement bond log findings at the initial stage, as well as submitting quality data to CDB.

All the software is conditioned for both individual and batch testing.

New Solutions to Ensure Data Quality and Integrity
To control the incoming file data integrity and track the information flow, TNNC specialists have developed ArchiveShare data flow management system. It includes of two subsystems.

The registering subsystem automatically receives the incoming data and includes it into own incoming database. The data sources may be an e-mail box, DVD, hard drives, or FTP. After this, the received data are located in dedicated file resources where they become available for further work.

The web-subsystem helps visualize these data. It has a set of functions to facilitate and manage data flow. Moreover, the web-subsystem uses e-mail to notify the users of key events, such as moving to the next stage of data processing or holdback.

To control data quality and integrity, CDB has tools for the comprehensive information assessment in data array. They help accumulate a studies knowledge hub which, in its turn, improves the data testing quality.

View Inkl is used to display and visually assess the quality of G&G information downloaded into BASPRO Database, including data on directional survey, segregations, layer intersection coordinates, wellhead coordinates, altitude, and correction of magnetic variation. The software enables us to track the path of an individual well or a whole well pad. Export Inkl is designed for modeling specialists. It helps obtain directional survey data for a PU from BASPRO Database. This can be done both in technical standard format (to submit data to regulators or contractors) and in a format ready to download into modeling software (subject to correction of magnetic variation).

In 2009 data management will become much more effective, upon implementation of technical standards and software for data quality control. The Company will be able to operatively track depletion of the remaining hydrocarbon reserves, simulate well interventions for enhanced oil recovery more accurately, and identify the most efficient and cost-effective options for reservoir development.

Labels: data management, Exploration, Information storage, production, Russia, seismic, TNK-BP, Tyumen

posted by The Rogtec Team @ 17:07  0 Comments

R.V. LUGUMANOV, V.P. YATSENKO

PROCEDURE AND ORGANIZATION OF WELDING AND ASSEMBLY WORK
The number of welds made during construction of the line part of the oil pipeline was as follows:
by manual arc welding (WPS-01 and -02 procedures) 4,730 joints of 30" pipes with wall thicknesses of 11.08 and 13.03 mm at an average daily rate of 0.9 to 1.2 km; by CRC AW automatic welding (WPS-13 procedure) 4,194 joints of 30" pipes with a wall thickness of 11.08 mm at an average daily rate of 1.5 to 1.9 km.

During seam overhead welding according to procedure WPS-01, the pipe joint was assembled on an internal self-propelled pneumatic lineup clamp with a clearance of 1.6-2 mm. Wedges were used to maintain the clearance during the joint assembly and welding process. The root layer of the joint was applied by two welders in approximately 9 minutes. Welding was done on straight polarity, which increased penetration of the pipe edges and welding speed. Electrode travel in the groove was downhill, resting the sleeve of the coating on the joint edges and forming a keyhole under the arc in the molten pool.

In the vertical part of the joint, when the molten metal and slag begin to flow under the arc, the welding current and travel speed were increased. In the overhead part of the joint, the welding current was reduced in order to reduce the weight of the molten pool and improve the formation of a reverse bead.

During the welding process, the welder also kept an eye out for any shift in the edges or change in the joint opening. If the edges shifted, the arc was directed at the farther edge and the electrode tilted toward the joint plane. At the same time, the welder watched out for any burnoff of the closer edge in order to prevent a lack of root penetration. The start-to-finish segments after each electrode were notched with a grinder and abrasive disk. The Indian welders, who were the most experienced, mostly did no notching, and after replacing the electrode continued welding. After the welding, mechanics flushed the joint perimeter, opening up the slag pockets.
Applying the second layer - the hot pass - is the most complex operation in welding with cellulosic electrodes. When applying the hot pass, Russian welders frequently use the wrong method - holding the electrode down without manipulating the end. Doing this requires that the root layer be thoroughly ground, which makes it thinner and thus results in the likelihood of burn-through of the root bead and an increase in the specified interval between the root pass and the hot pass of more than 5 minutes. This leads to reduced diffusion of atomic hydrogen out of the seam and the danger of cracks appearing. The correct way to do the hot pass is by a whipping motion of the electrode tip so that slag is swept out of the pockets. In addition, the welding current source should be set for a steeper volt-ampere curve while keeping the welding current at maximum (in accordance with WPS-01).



The fill layers of the weld were deposited using 4.0mm diameter Fox BVD 85 electrodes for vertical down welding. During the welding process, the arc length should be as short as possible due to the increased tendency to form pores, including start and stop pores. The electrode tip is weaved from side to side in a zig-zag motion without increasing the arc length where the direction changes at the edge of the joint. The missing fill in the groove on the vertical sections of the joint (10-8 and 2-4 hrs of the perimeter) is completed with a final (correcting) fill layer so that it is flush with the pipe edges. On the remaining sections of the joint perimeter just before the face layer is applied, the groove should be unfilled for approximately 0.5-1.0 mm to the pipe edges.

The face layer of the seam is deposited with the welding current set at 20-30 amp less than that used for the fill passes. The width of lateral oscillation of the electrode should not be more than twice its diameter. The width of the layer should be 3-4 mm greater than the width of the groove after the fill layers have been deposited. To avoid undercuts along the edges in the overhead position, the lateral oscillations of the electrode tip should preferably be U-shaped instead of zig-zag. With this welding technique the arc length must be kept as short as possible to avoid pores forming in the overhead position due to insufficient arc protection. For joining pipes with wall thicknesses greater than 15 mm, it is advisable to apply the face layer in two parallel beads.

The actual rate of seam overhead welding using the WPS-01 procedure was 15-20 minutes per joint. The overhead team consisted of 10 welders working simultaneously in 5 welding tents:

• Tent 1 - root pass, average welding time 9 min;
• Tent 2 - hot pass, average welding time 4 min;
• Tent 3 - fill pass, average welding time 12 min;
• Tent 4 - fill pass, average welding time 11 min;
• Tent 5 - face pass, average welding time 13 min.

The supply sources used were 2-station and 4-station Arcotrac and Liebherr welding tractors fitted with Lincoln DC-400 welding rectifiers.

For the CRC AW automatic welding (WPS-13 procedure) there were 11 welding operators: one for the internal welding heads and 10 for the external welding heads. They worked in five tents:

• Tent 1 - hot pass;
• Tent 2 - 1st fill pass;
• Tent 3 - 2nd fill pass;
• Tent 4 - face pass;
• Tent 5 - face pass.

In line with the procedure requirements, before being welded the pipe ends were cut with hydraulically-driven circular cross-saws to obtain a special, narrow-gap two-sided bevel. This operation was done by a team using two circular cross-saws with hydraulic stations on the pipelayers. The guide belts for moving the welding heads along the pipe joints were mounted by the following team.

The head team of the welding column assembled the pipe joints (with no clearance) on an internal pneumatic self-propelled lineup clamp combined with a welding machine that welded the root layer of the joint from inside the pipe using six welding heads. The remaining teams welded the outside layers inside the tents listed above using external welding heads and solid-section 0.9 mm diameter wire. The root and face layers were applied in a shield gas mixture of argon + carbon dioxide (75% + 25%), and the hot pass and fill layers in carbon dioxide (100%). All the layers were welded downhill. The system comprised one 4-station (Liebherr) and five 2-station (Arcotrac) welding tractors with hydraulic boom manipulators from which the welding tents were suspended.

Welding of lap joints, taper joints and line valve assemblies was done according to procedures WPS-02 and WPS-03 using external lineup clamps. The joints were assembled using rigid external lineup clamps manufactured by CRC Evans and break-over lineup clamps produced by Russian manufacturers. Experience showed that the CRC Evans clamps were better at eliminating the height difference of the pipe edges in the joint since they use a hydraulic jack. The drawbacks of these clamps are their considerable weight, the difficulty of depositing the root layer around 50% of the perimeter before the clamp is removed, and their high cost compared with Russian-made external lineup clamps.

The pipe joints were assembled with a clearance of 2.5-3 mm. For applying the root layer, 3.2 mm diameter electrodes were used. The welding direction was from bottom to top - uphill. Polarity was straight for welding with cellulosic electrodes and reverse when using basic-coating electrodes. Two welders working at the same time apply about 50% of the root layer perimeter on the external lineup clamp, after which the clamp is removed and welding of the remaining 50% is completed, making sure to notch the start-finish sections.

One of the important factors in welding these kinds of joints is to maintain the preheat temperature. The method traditionally used in pipeline construction whereby the joint is preheated until the external lineup clamp is fitted leads to a drop in the preheat temperature at the start of welding the root layer (to below 80-1000C) and consequently to the likelihood of cracks appearing. To eliminate this drawback, the diameter of the collar burners was increased so that preheating could be done after assembly with the external lineup clamp in place on the pipe joint. The fill and face layers were welded downhill with basic-coating electrodes according to the WPS-01 procedure or uphill according to the traditional WPS-23 procedure.

Lap joints were removed by teams consisting of two pipelayer operators, a welding tractor operator, two welders, a gas cutter, foreman, and a rigger. Lightweight fan-type tents developed by Russian specialists from their experience of earlier projects were used to protect weld areas.

Installation of surge relief stations on the existing SHBAB-1 oil pipeline was carried out without halting the oil flow by means of hot taps - welding split tees to the oil pipeline and then tying in safety valve stations using TD Williamson equipment.

Welding of split tees for hot taps was done using the WPS -10, -11 and -12 procedures. The members of the split tee were mounted onto the operating pipeline at the tie-in point and held in place on the pipe by two break-over external lineup clamps. First, two horizontal seams were welded to join the two members of the tee into a single structure. Welding was done with beads using the step-back method. The clamps were allowed to be removed after 25% of the cross-section of the horizontal seams had been welded. After the horizontal seams were welded, circular fillet welds were made to join the tee to the pipeline. Welding was done from the bottom up with separate beads using the step-back method by two welders at the same time. The anchor flanges were welded in the same way.

Defects were removed using the WPS-03 and -28 procedures by repair teams consisting of an experienced welder and a welding tractor operator.

According to client specifications, a repeat repair was permitted one time.

Repairs were made both outside and inside the pipeline. The defects were marked out by the repair team using a measuring band (similar to the bands used by defect detector operators). The defects were ground with abrasive disks. For repairing a root layer from the outside, abrasive disks 2.2 mm thick were used for a section that was to be cut through, and for all other cases the thickness was 4 and 6 mm. Grinding of the defects was generally done by the welding tractor operator, but if a through cut was required, it was done by the repair welder with a hacksaw to obtain an even opening of 2.5 - 3 mm.

To reduce the likelihood of cracks appearing during repair of the root layer of lap joints, the following sequence of process operations was used in the project:

• preheat the joint to be repaired using a propane collar burner to 120 - 150 0C;
• remove the defective section;
• reheat the joint again, immediately before welding, to 120 - 150 0C;
• weld the defective section while strictly maintaining the interpass temperature;
• when welding is done, put a thermal wrap around the joint to reduce the cooling rate.

When the root layer of lap joints was repaired in the above sequence, there were ultimately no cracks.

Of great practical interest here was the welding process monitoring procedure that was developed in line with the quality management system and used in the project.

At the preparatory stage it is verified that:

• the relevant (approved) welding procedure is available;
• the pipes meet project requirements and the specifications, and that they are free of unacceptable defects;
• welders and welding operators have the appropriate (unexpired) certification;
• welders are properly equipped (coveralls, boots, leggings, mask, electrode holder, electrode case);
• the equipment and tools are available and in working condition (correct lineup clamp, clearance wedges, electric grinders, return lead clamp, welding protection tents, welding cable, welding current remote control, grounding at end of welded pipeline string, pipe rollers);
• the beveling of the pipe ends matches, including geometry;
• the joint is correctly assembled, including fulfillment of requirements regarding the offset of factory-welded seams and their location;
• the equipment for preheating the pipe ends is in good working order;
• welding materials are prepared (baked) and that they have certificates;
• the welding machines are in good working order.

During the welding process the following are monitored:

• size of the root opening and the amount that it changes during the root pass;
• use of no less than two welders simultaneously for welding pipes more than 12" in diameter;
• removal (release) of the lineup clamp;
• interval between completion of the root layer and start of the hot pass when using an internal lineup clamp;
• the welding current;
• quality of cleaning of each pass;
• that welding is performed in line with the specified procedure;
• absence of arc striking on the body of the pipes;
• completion of the prescribed number of passes;
• interpass temperature meets requirements;
• use of thermal wraps.
• When the welding is completed it is checked for seam geometry and absence of visible unacceptable defects. The edge misalignment is measured and the weld is inspected to make sure that it has been cleaned of slag and molten metal spatter, and that it has been appropriately marked.

The final operations at the end of the work shift are to cap off open sections of the pipeline, complete welding of the face layer on all the welded joints, verify the number of remaining electrodes, and clear away any foreign objects from the production area.

WELDING QUALITY CONTROL AND BASIC DEFECTS IN WELDED JOINTS
Welding quality control was subcontracted to Vetco, a local company that used gamma defect detectors and X-ray machines, including self-propelled pipeline crawlers for internal pipe inspection. The fillet and horizontal welds on the split tees were inspected using powder magnetography and dye penetrant examination. The average percentage of seam overhead joints inspected was 10% of the total number welded, but the overhead joints welded by the CRC AW automatic welding machine were 100% inspected using a Pipewizard automatic ultrasound computer system made in Canada. The inspections were performed by Stroytransgas engineers.

In pipeline construction practice outside Russia, welding quality is generally assessed based on the percentage of unacceptable defects out of the total number of joints:

• up to 5% is excellent quality;
• up to 7% is good quality;
• up to 9% is satisfactory;
• more than 10% is unsatisfactory.

At the facility that was built, repairs were made to 155 joints that had been welded on the CRC AW automatic welder, and to 410 manually welded joints. The total percentage of repair was 6.33%, including 8.6% for manual welding and 3.7% for automatic. Applying the international assessment criteria it can be stated that the quality of manual welding operations was good, and automatic welding excellent.

These levels were achieved thanks to constant monitoring by the office of the project's chief welding engineer, analysis of the causes of the weld joint defects, and determination of the methods to remedy them.

The results of this work are summed up in Table 1, which shows the typical defects encountered in manual arc welding on the project, their causes, and their remedies.



Rasil Varisovich LUGUMANOV, Chief Welding Engineer of the project's construction department in the Kingdom of Saudi Arabia

Vladimir Petrovich YATSENKO, Acting Deputy Chief of the Construction Technologies Department, chief welding engineer of Stroytransgas, PhD

Labels: pipeline welding, Russia, SHAB-1, stroytransgaz

posted by The Rogtec Team @ 17:27  0 Comments

Dean Watson, Vice President of Schlumberger's Drilling and Measurements business in Russia.



Kieran Fitzpatrick, Operations Manager, Halliburton Sperry Drilling, Russia




Vitaly Chubrikov, Baker Hughes INTEQ, Business Development Manager, Russia



Brod Sutcliffe, Global Business Development Director for Weatherford Drilling Services

ROGTEC: What are the key advantages of ERD for the Russian market place?

Dean Watson: The key advantages for ERD in the Russian market place are the same as they are in other market places: a cost effective solution with proven ROI, an environmental solution or an accessibility solution. By a cost effective solution the meaning is rationalization of ROI for the infrastructure required to exploit the assets. If ERD proves to be the most cost effective solution taking into account other drivers such as environmental issues or accessibility then it makes sense for our clients to use this technology. In some cases ERD can be rationalized in Russia to address environmental concerns or in areas where there is limited infrastructure.

Kieran Fitzpatrick: Specific advantages of ERD are as follows:

1. Extend life of mature fields (producers/injectors).
2. Satellite field developments.
3. Eliminate drilling/production islands.
4. Access reserves in environmentally sensitive areas.
5. Traditional ERD, e.g. the world class wells in Sakhalin, where the use of a land rig and onshore production facilities to access offshore fields are much less expensive. They are able to operate all year (unlike offshore rigs in the frozen ocean), and more efficiently (but less expensive) environmental and safety compliance.
6. Multiple well ERD from Russian tundra locations (pads), resulting in less environmental & ecological disturbance, as well as the ability to drill under lakes & rivers e.g. under Samotlor Lake.

Benefits

1. Access reserves economically.
2. Fewer pipelines - reduction in costly subsea equipment.
3. Bring production forward.
4. Re-assess opportunities previously uneconomic.
5. Plan new bespoke ERD developments.

Vitaly Chubrikov: ERD technology has different potential and applications for both mature (brown) and new (green) fields; outlined below are the separate advantages:

Brown fields:

Capital costs reduction; most of production comes from W. Siberia where pad drilling is standard, due to the swampy landscape and limited existing infrastructure. ERD will allow the drilling of wells with longer range from existing pads to reach field areas which would normally require building new pads

Better production and longer wells life cycle. ERD employs Rotary Steerable Systems and Logging While Drilling technologies; the combination of these provides accurate wellbore placement in better quality reservoir zones that ensures better production and longer life cycles with ERD wells

Better production from complex water flooded fields; ERD will allow the setting of multiple geological targets to produce from several relatively good zones within water flooded zones Green Fields:Less capital intensive field development projects. Pad and infrastructure construction on land (access roads, pipe lines, energy lines etc) are a significant part of capital investments to develop Green Fields, in some cases more than half of the entire field development costs. Introduction of ERD wells will allow the development of green fields from fewer pads, which will significantly reduce development costs.

Development of offshore green fields are even more capital intensive, and so the potential of capital cost reduction through the application of ERD technology is even better.

As already mentioned above, the advantages of RSS and LWD technologies are also fully applicable to green fields.

Brod Sutcliffe: Weatherford offers a full range of drilling services for ERD wells. Our Revolution Rotary Steerable and Weatherfod LWD systems can be combined to provide an excellent Extended Reach Drilling System. We offer the Revolution System in all hole sizes and we now offer both wired and wireless motorized RSS options for increased bit speed and ROP. Our LWD systems holds world records for Pressure, Temperature, Dog Leg and for pulse detection in extreme drilling environments - a key attribute for ERD drilling. Our LWD systems offer a full complement of azimuthal measurements for GR, Spectral Gamma Ray, multi-frequency resistivity, azimuthal density and thermal neutron porosity.

All azimuthal measurements deliver both realtime and recorded data imaging and this data can easily be transported to any location with our Realtime Operations Service.

ROGTEC: Outside of the current economic situation what is the market and potential for ERD in Russia?

Dean Watson: Although ERD is currently relatively small in Russia, this technology will continue to grow as offshore assets and eastern Siberia are developed.

Kieran Fitzpatrick: Sakhalin is the biggest market in Russia remaining at 1 P3 rigs. ERD wells can bring additional reserves on line which may not be otherwise accessible with conventional well designs. As new reserves are identified in more isolated and remote locations, ERD well designs will have increased applications.
Please also refer to the below reference on potential fields

Vitaly Chubrikov: Declining production in brown fields will make operators look for technologies to maintain or improve production, at increasing costs; eventually ERD would become economical for operators.

Green field development will definitely employ ERD technology for discovered fields in the Barents Sea, Caspian, Sakhalin and Eastern Siberia.

However at the moment ERD application is also limited by existing rigs fleet technical capabilities Р in reality there are just a few rigs available across Russia technically capable to drill wells over 6,000m MD.

Brod Sutcliffe: ERD drilling can dramatically reduce the environmental wellsite footprint of an operation as well as significantly reduce capital cost. Any market where these issues are concerns will benefit from ERD drilling.

ROGTEC: What are the key fields and regions for this technology?

Dean Watson: Geographically potential markets exist where there are offshore assets as well as accessibility issues potentially caused by a lack of infrastructure. The following come to mind: Sakhalin, the Caspian, the far north and eastern Siberia.

Kieran Fitzpatrick: On Sakhalin, Odoptu and possibly others; remote tundra fields in NW Siberia and fields where the cost of a platform is prohibitive, e.g. Shtokman. Also, Near-shore fields in the Barents Sea and Ob River delta (areas frozen in winter so not suitable for platforms) by ERD. Inland ERD wells are likely to get longer from larger tundra pads to reduce environmental footprint.

Vitaly Chubrikov: Barents Sea, Caspian, Sakhalin, Eastern Siberia, some recently discovered fields in W. Siberia and Komi in remote areas.

ROGTEC: What are the key factors for success in planning and delivering ERD wells?

Dean Watson: Key factors for the success in ERD are: innovative technology, people expertise, process organization and communication. Appreciation to the cost involved and the potential downside if there is a major or catastrophic event should be fully understood. Success is in the planning and detail and Schlumberger has a proven track record to successfully delivery ERD wells.

People and the competency of people at the wellsite are important elements to the delivery of ER wells and so developing knowledge and expertise, through training should be put in place well in advance. Promoting communication between all members of the project will provide another success factor.

Time for the planning cycle is essential. Drilling an ER well is not just an extension of a typical directional well. Depending on the scale of the project or well, the required or suggested planning and lead time could be between 2 to 4 years lead time, from the conceptual phase through to spud.

There are numerous design criteria that have to be considered in detail for ERD. The final geometric profile and planned well trajectory is key, especially the build up section. This section must be planned to accommodate minimal tortuosity and a "smooth" well bore, a factor that plays an important deliverable in the final execution of the well and the ability to run tubulars throughout the well.

Other factors that have to be managed are wellbore stability, ECD management, wellbore positioning and real-time monitoring. The later point illustrates the requirement to plan for the ability to maintain good data telemetry and data management throughout the well execution.
ECD management and planning is vital during the modeling phase as this alone could be a limiting factor for the well delivery and operations. Planning for realtime monitoring is essential so as the drilling progresses the performance versus the model can be tracked and updated as necessary.

Operational challenges have to be evaluated and contingency planning put in place. Torque and drag, hole cleaning, barite sag, well control, these are all additional factors that have to be considered at the design phase. This is where the selection of the correct downhole drilling technology is critical. Rotary steerable systems are now the drilling technology of choice for ERD, as they provide the opportunity to deliver continual rotation, promote good hole cleaning and hence avoid the opportunity for stuck pipe or inducing pack-offs or poor well bore stability.

The completion type and any future well intervention must be considered as one of the primary design criteria.

In line with all the design factors, obviously then the rig must be sized to accommodate all the operations from drilling, tripping, completion running and workover capability, all of which may require upgrades to the equipment or sourcing of an ERD capable, specific rig.

Kieran Fitzpatrick: An ERD well is a very sensitive system so it is essential that with so many variables that can affect the eventual success of an ERD project that all aspects of the wells are very carefully planned. There must be a total team effort during the planning and execution of the well. Drilling Environment, Well Engineering and well designs, and drilling parameters play a very important role in ERD Well Design:

Drilling Environment:
Onshore / Offshore
Lithology
Shallow Gas
Pore Pressure
Fracture Gradient
Depleted Zones
Faults
Seismic Data

Well Design:
Profile Design
Hole Size
Casing Designs
Torque and Drag
Hydraulics
Hole Cleaning
Borehole Stability
Risk Mitigation
Lessons Learnt

Drilling Parameters:
Drill String Design
Rig Limits
Mud Design
Operating Procedures
ECD Management
Directional Control
New Technology
Casing Running
Completions

During the planning phase, great care must be taken to get the best possible rock strength analysis done. The second critical part of the planning phase is the best possible torque & drag modeling. This should include drilling fluid lubricity testing. Accurate Equivalent Circulating Density (ECD) & hole cleaning modeling are also required.

It is also essential to determine/model whether casing will run in the hole conventionally. Premium casing threads are needed, as the casing may have to be pushed. It may be necessary to float casing into at least one hole section, as well as running roller centralizers.
In the operating phase, torque & drag monitoring is the most important parameter to monitor the build up of cuttings' beds in the low side of the hole. Consistent procedures to measure pick-up/slack-off weight & torque on connections are essential. Premium drilling fluid lubricants, e.g. TORQ-TRIMЁ 22 lubricant will be needed as well as mechanical torque reduction equipment, e.g. drill string torque reduction (DSTR) subs. Both factors (torque & drag and fluid lubricants) are essential during well completion as well as drilling phase.

Another key item is the final completion string. Well screens with a Swellpacker isolation system are a proven option to cementing which is very difficult in long horizontal sections.

Finally, the rig must have the capability. The drill string will see big loads, so premium connections are required. Big pipe (5-7/8" or 6-5/8") is recommended for more pulling power, more torque, less buckling & better hole cleaning. The pumps must be big & the standpipe pressure rating adequate (5000 psi recommended). The top drive must be able to rotate at least at 120 rpm with high torque loads. A Pressure-while-drilling (PWD) tool is needed to monitor ECD.

Every tool, joint of pipe, sub, etc. should be benchmark tested, labeled & hours tracked in a register to minimise the risk of failure. Non-spec tubulars & tools should be removed from the rig.

The shakers must have the ability to handle high flow rates with high cuttings' loads through fine mesh screens. The concentration of ultra-fine solids builds rapidly due to "mortar & pestle" grinding by the drill pipe against the low side of the hole, so extra centrifuges & high dilution rates are needed.

The key is careful planning. You need enough time & resources to do this thoroughly.

Vitaly Chubrikov: Good geological field knowledge; custom-planned wells; involvement of the Operator, Rig Contactor and Service Companies engineering, geological and operational experts in all well planning and execution and a lessons-learned cycle to improve efficiency and performance on each following well.

Brod Sutcliffe: ERD drilling is in most cases an offshore operations. There is limited activity onshore to the high cost. However difficult terrain, environmental site issues and near shore locations to offshore reservoirs can bring an opportunity to onshore ERD. Any fields agreeable to the business drivers such as limited surface access or superior economic choice would be open to an ERD application.

ROGTEC: What are the key benefits of your specific ERD solution?

Dean Watson: Obvious benefits of our specific ERD solution would be to deliver the well with good performance, with in the project time line and cost effectively. Good planning and lead time would ensure that the correct and appropriate technology, services and rig selection or upgrades could be planned and delivered. Ultimately resulting in a final proposed well design to reduce risk and maximize success. This is based on Schlumberger's leading position in the ERD market and a proven track record with both appropriate technology and the people (their knowledge and expertise) to make this happen.

Kieran Fitzpatrick: Halliburton's Sperry Drilling and Drill Bits and Services provide a matched drilling system that minimizes the amount of ‘spiraling' in the wellbore. Our ‘point-the-bit' Geo-Pilot rotary steerable system matched with a long-gauge Geo-Pilot bit deliver a smooth, non-tortuous wellbore. When spiraling in the well occurs over the many thousands of meters it can result in numerous problems such as excessive torque and drag and poor hole cleaning. Elimination of this spiraling increases the chance of being able to drill the section successfully and minimizes problems when running casing or completions. In addition, Sperry Drilling has a comprehensive range of logging-while-drilling (LWD) sensors which can provide solutions for formation evaluation, geosteering and wellbore stability without having to use wireline logging techniques which can be expensive, difficult and risky in an ERD well. Using Max3Di drilling optimization software, directional drilling efficiency and reliability can be increased by immediately detecting out-of-bound conditions. Drilling costs can be reduced and the decision-making process can be expedited by providing key data to personnel both at the rigsite and in Real Time Centers, where drilling performance can be modeled before going downhole to choose optimum parameters and avoid surprises. Post-well analysis with instant replay allows us to identify problems and work on solutions for future wells.

For Sperry Drilling the key advantages are as follows:

1. Experience in drilling extended reach wells in different counties around the world.
2. Well Engineering Design and planning, specific engineering group.
3. Real Time CentersStrataSteer 3D geosteering service.
4. BHA analysis with MaxBHA software.
5. Well optimization of drilling parameters. Max3Di drilling optimization software. Quicker drilling times and reduced formation exposure time.
6. GeoTap formation pressure tester and pressure-while-drilling LWD tools aid with the calculation of correct formation pore pressures and ECD circulating pressures to help maintain the optimum mud systems and hole cleaning. This enables ERD wells to be drilled with real-time data transmission.

Mud systems, Baroid:

1. Experience (Baroid have engineered 25 of the 30 longest reach wells in the world).
2. Suitable fluids, engineered for stability, lubricity & minimum ECD.
3. DFG software for best-in-class hydraulics & ECD prediction.
4. Premium lubricants for drilling & completion fluids.
5. Wellbore stability software & wellbore strengthening technologies & products (WellSET Lost Circulation Treatment).
6. Optimized theology under downhole conditions for maximum hole cleaning.

Vitaly Chubrikov: Large local and international ERD experience; complete portfolio of technical expertise, superb equipment and state-of-art software.

Brod Sutcliffe: For Weatherford Drilling Services our products are: Rotary Steerable Technology, Full LWD capability, Azimuthal measurements with realtime imaging for accurate geosteering, Realtime Operations and Drilling Optimization (Vibration, PWD, BHA design).

ROGTEC: What are the most common problems which occur in the Russian market with ERD?

Dean Watson: The challenges in the Russian market are the same as they are in other ERD markets.

Kieran Fitzpatrick: The main problems are a lack of understanding of the benefits of ERD, a lack of planning and expertise and lastly a lack of drilling rigs capable for ERD.

Vitaly Chubrikov: The cost of ERD still does not allow economical application for brown fields. Also lack of technically capable drilling rigs.

ROGTEC: How can well bore instability be minimized pre and during drilling ops?

Dean Watson: Well bore instability can be minimized by review and root cause analysis of offset well data as part of the planning phase. This may entail full geomechanics studies to evaluate the zones of potential challenges, the stress direction, formation and compressive strength and breakout characteristics.

Working with the drilling team in the development of good drilling practices and training during the pre planning phase helps identify and promote awareness of key issues amongst the whole team. This allows for the experts to communicate the mitigating measure to be deployed and the urgently of quick identification and communication during the execution phase.

Once in the drilling phase then adherence to the set and agreed drilling and operation practices should be followed and monitored in realtime. Monitoring and comprehension of the events and risks throughout the hole section and early identification of hole changes is essential.
Mud chemistry and theology are key aspects that also require good design to address the wellbore stability but must also deliver the necessary characteristics as a drilling fluid to aid the complete process.

Kieran Fitzpatrick: A thorough well-bore stability evaluation needs to be carried out encompassing regional tectonics, structural analysis and experience from wells that have been drilled in the same area. By carefully planning the well direction and profile, well bore instability issues should be minimized. While drilling, hole conditions should be carefully monitored for signs of borehole deterioration. In addition, LWD sensors can provide early warning signs of borehole instability and provide valuable information on stress directions.

In summary:
Accurate rock strength measurement & geomechanical analysis.
Proven drilling fluid technology.
While drilling, adequate mud weight, based on rock strength analysis.
Good hole cleaning modeling & practices.
Well thought-out circulation & tripping practices.
Understand the effect of high ECD's on borehole stability & induced lost circulation, especially in ERD wells at shallow true vertical depth (TVD).

Vitaly Chubrikov: The question requires the writing of an additional article! It is a very complex problem which does have technical solutions, individual to each field. Usually solutions are around drilling fluids properties, drilling parameters and practices.

Brod Sutcliffe: Pre-well planning can assist in optimizing the well profile, the mud program and the BHA design. Then, while drilling, we monitor in realtime, ECD, cuttings removal, Stick-Slip, three-axis vibration, temperature, bore/annular pressure etc. to reduce wellbore instability.

ROGTEC: What are some of the key indicators of problems during drilling an ERD well?

Dean Watson: Indicators normally manifest themselves very quickly and unfortunately on ER wells they can have catastrophic effects on the well or project. The key is obviously in the avoidance of such problems and as stressed above this is why the planning stage is so critical as well as the level of expertise of the people involved. Schlumberger has a good track record in helping our clients to minimize such problems.

Ensure that all critical parameters have been modeled in advanced and actual data is available to evaluate trends. Calibration of wellsite data is essential for the maximum value to be extracted from the realtime data versus the models (which have been validated against offset information). Clear divergence from the established pre-drilling models which are being updated in realtime for all phases of the operation (drilling, tripping, and casing running), for example torque and drag, ECD, vibration, stick slip and other drilling dynamics. Continuous review of formation and associate uncertainties are also key indication of variations to the plan which may require immediate evaluation and changes to the predicted models.

Kieran Fitzpatrick: When an ERD well is planned, a comprehensive "road-map" of expected measured parameters should be produced from modeling expected scenarios. Any deviation from what has been expected is an indication that there may be problems. Typically, the well will be monitored from a Real Time Centre (RTC) which may be located at a remote location some distance from the actual well location. The RTC may, for example, be located at the operator's main office where teams of experts can monitor the well's progress while also monitoring wells at other locations. This allows for the maximum use of what are becoming increasingly scarce, experienced personnel.

Inadequate hole cleaning in large diameter, high-angle hole sections.
Deviation of actual torque & drag away from modeled trends.
PWD data indicating excessive annulus cuttings' loads.

Vitaly Chubrikov: Again, it is a difficult question and depends on the problems observed. Not to be specific, these could be excessive torque & drag, pressure increase, decrease or fluctuations, fluids losses or gains, cuttings volume etc.

Brod Sutcliffe: The critical issues for ERD would be ECD management, hole cleaning and hydraulics, drillstring mechanics (Torque and Drug), wellbore stability, drilling fluid, casing issues, drilling operations issues, pro-active geosteering and navigation. ERD wells can be technically challenging to plan and implement. What advise would you offer an operator considering and ERD solution?

Dean Watson: Invest in the upfront planning cycle. Getting it right first time requires good and extensive planning. Good planning will allow the operator to avoid an incident that may lead to a disastrous scenario. This potentially disastrous scenario is the major cost element that will affect the ERD project budget.

People are a key asset. Developing expertise and competency is essential and additional formal ERD training should be considered.

Know what works. Know what the limits are and find effective solutions. Develop a learning curve on the ERD campaign. Do not start with the most difficult well first. Capture as much information and lessons learned as possible to update and validate the models for the project or field. Data is essential. Success is in the detail.Bring together the operational teams during the preparatory phase to gain specific ERD training and to also highlight the key challenges that are expected during the execution. This also provides the opportunity for new ideas or challenges to be presented prior to spud!

Peer reviews are key to helping to identify whether the process has been followed and whether there are any potential show stoppers or barriers that have been missed in the planning phase.
Ensure that the well objectives have clarity and are understood by all. Selection of the appropriate technologies is essential and inline not only with the objectives but also to provide the necessary data to execute the well whilst minimizing the risks.

For today's ERD execution the benefits of realtime monitoring and support from the organization in town is now seen as a major way forward. The opportunity to engage not only the wellsite experts but those who have ownership of the well design programs in town can only add benefit and reduce the operational risk. Communication is key.

Kieran Fitzpatrick: Plan every aspect of the well, have a plan for every eventuality and learn from the experience of others who have drilled similar types of wells.

Consult with contractors and specialists that have extensive experience in this area. Careful planning is also required as per previous comments.Upgrading the rig and contractor equipment to meet the required objectives, for example hookload, torque, flow rate standpipe pressue etc is also essential.Using premium equipment such as top drives, downhole equipment, tubulars and connections and fluids also.

Technology used to push ERD limits:

Rotary Steerable Systems (RSS).
Casing / liner drilling systems.
Casing / liner flotation methods.
Pressure While Drilling (PWD).
Torque and Drag management.
Learning / knowledge transfer.

Vitaly Chubrikov: Economics: ERD costs vs. production over well life.

Good understanding of expectations and goals to select appropriate available technologies.

Solid understanding of the field geology and associated challenges.

Brod Sutcliffe: Good pre-well planning, alignment of operational objectives, good communication with all operational groups (Drilling, Geology, Completions, Reservoir, Petrophysics) and the selection of fit-for-purpose technology for job execution.

Dean Watson, Vice President of Schlumberger's Drilling and Measurements business in Russia Dean Watson is currently the Vice President of Schlumberger's Drilling and Measurements business in Russia. A 16 year veteran of the oilfield, he has held several Operational and Headquarters positions.

He graduated with a Mechanical Engineering degree from the UK and immediately put his education to use as a design engineer in one of Schlumberger's Technology Center. After several years in various positions he was then transferred to headquarters to lead a road map for new technology in Drilling Tools. A few years later he was then able to see first had the results of this work when he assumed a role as Operations Manager for China, Japan and Korea. Before assuming the VP position in Russia he was the world wide Operations Support Manager for Drilling and Measurements at Headquarters.

Kieran Fitzpatrick, Operations Manager, Halliburton Sperry Drilling, Russia Kieran has been based in Moscow for 2.5 years and in Russia for 5 years. He started in the North Sea in 1985, and has been with Halliburton since 1988, primarily working in the Middle East (Dubai / Abu Dhabi / Oman / Qatar / Pakistan / Bahrain / Egypt / Yemen / Saudi Arabia). Kieran was educated at the Belfast Municipal Institute and The Queen's University of Belfast.

Vitaly Chubrikov, Baker Hughes INTEQ, Business Development Manager, RussiaVitaly Chubrikov graduated from Gubkinsky Oil & Gas University in Moscow in 1995 and joined Baker Hughes soon after, as a field engineer. Over the years he has held various field and office positions in both domestic and international assignments.

Brod Sutcliffe, Global Business Development Director Weatherford Drilling ServicesBrod Sutcliffe has worked in the oil & gas drilling industry for 29 years since graduating in Geology from Leeds University, UK. After spending several years in the field as a wellsite geologist, LWD engineer and directional driller, Brod has held a number of operational and business development management positions.

Labels: Baker Hughes, ERD, Extended Reach Drilling, Halliburton, oil gas, Russia, Schlumberger, Weatherford

posted by The Rogtec Team @ 09:35  4 Comments