Workover Best Practices

RO-EP-DA-PO-06-POL-001-02 OMV Petrom Exploration Production

Revision 1 2012 OMV Petrom Workover Best Practices

http://www.petrom.com

Title WORKOVER BEST PRACTICES

Prepared by CMS Prodex Dr Miso Solesa Technical Consultant

Content checked by DA-PO-WO Department

Ivan Vukov Department Manager

Content reviewed by CII Consulting Harald Zetche Technical Consultant

Approved WO&WI BU

DA-Operation Roland Perdacher Senior Head of Operations

WO/WI BU Urlich Winter Director of Workover & Well Intervention BU

DA Gabriel Selischi Director of Domestic Asset Business Unit

Organizational Entity Name/Title Date Signature




WORKOVER BEST PRACTICES OMV Petrom continuous drive towards quality and performance improvement includes among others the need for definition of workover standards. Known the importance and the complexity of the workover operations in OMV Petrom Romania, bringing them to international industry standards level is mandatory. Thus workover standards have been defined within SIRIUS II project and they include the Workover Best Practices (the design phase, or what is to be done), the Workover Procedures (the execution phase, or how to perform workover operations) and the Workover Rules (the basic workover principles). The document herewith represents the Workover Best Practices developed and released in 2012. Workover Best Practices is a technical document containing information regarding most applicable engineering solutions, equipment and tools used during workover operations of oil, gas and injection wells. This document has been developed & compiled by an external technical consultant based on current OMV Petrom workover practices, worldwide recognized workover practices & standards, as well as on latest developments in workover and well service technologies. During preparation of WO Best Practices there was a continuous communication between different parties and technical authorities. Among them DA HQ Production Operations Well Completion department, Sand Control & Stimulation department, Production Optimization department and Workover department, moreover WO/WI BU HQ, as well as field experts from both DA Operation and WO/WI BU (Assets). OMV Austria Workover & Drilling department technical staff has also contributed during preparation of the WO Best Practices. In total there are ten specific areas of workover best practices with detailed information regarding the specific topics. Each of these best practices has also an Executive Summary in order to guide the reader through the main ideas and focus onto most important practices. This document is primary addressed to the engineering staff involved in the workover design, planning and program preparation - both Operations and Services. Furthermore other parties involved into well operation and subsurface maintenance process will also benefit from WO Best Practices document. OMV Petrom E&P staff will have to ensure that these WO Best Practices are implemented and will be used on regular bases during workover operations. OMV Petrom Workover Best Practices is intended to be a live document. With development of new technologies and changes of the working environment this document will be updated accordingly.




Content

1. GENERAL INTRODUCTION 2. WORKOVER BEST PRACTICES METHODOLOGY 3. RIG SPECIFICATIONS 4. WELL CONTROL 5. WELL RECOMPLETION 6. PERFORATING 7. TECHNOLOGICAL OPERATIONS 8. WELL REPAIR 9. STIMULATION BY ACIDIZING 10. SAND CONTROL 11. STIMULATION BY FRACTURING 12. ZONAL ISOLATION


Revision 1 2012 OMV Petrom Workover Best Practices 1. GENERAL INTRODUCTION

1. GENERAL INTRODUCTION

Contents

1. GENERAL INTRODUCTION ................................................................................................................ 1-1

1.1 Purpose of the Manual ............................................................................................................ 1-1

1.2 Contents ................................................................................................................................... 1-2

1.2.1 Source of Information ........................................................................................................ 1-2

1.2.2 Ownership .......................................................................................................................... 1-2

1.2.3 Confidentiality ................................................................................................................... 1-2

1.3 Updating, Amendment and Control ........................................................................................ 1-2


Revision 1 2012 OMV Petrom Workover Best Practices 1. GENERAL INTRODUCTION

http://www.petrom.com 1-1


The latest initiative for WO Services improvement for the period of 2012-2016, as part of the SIRIUS II Project Continuation, calls for preparation of Workover Standards in OMV Petrom. The essential part of WO Standards is the WO Best Practices Manual (sub-project). This document has been created to provide a comprehensive description of WO services, equipment, conditions and other requirements for safe and professional WO operation within OMV-Petrom Romania.

The Best Practices are non-binding company recommendations. All employees, active in field operations, should, however, get acquainted with those Best Practices relevant to their responsibilities. More detailed information can be found in subsequent sections of this document.

1.1 Purpose of the Manual

This comprehensive manual has been compiled with the main purpose of serving as a guide to Workover Operations (WO) personnel and a reference to new Workover Engineers. The most common OMV Petrom WO have been presented in this document to familiarize the reader with the actual workover Best Practices (BP) achieved in OMV Petrom and step by- step technology procedures to plan workover operations and to select the best technology and sequences required for preparing a detailed technical program in order to start with the job execution. This document is written in such a way that it is clear, easy to follow; it uses acceptable oilfield terminology, and the information is current and very specific for Petrom OMV operations.

Additionally, the purpose of this document is to guide OMV Petrom experienced engineers of all technical disciplines how to implement efficiently the best practices and workflows in the process of planning, designing, executing, supervising and monitoring results of workover operations and its importance on achieving the targeted KPI. These, in consequence, have a large impact on costs and field profit. The Corporate Standards in this document define the requirements, methodologies and rules that enable the operation to be uniform and in compliance with the Corporate Company principles. This, however, makes each individual part of the WO processes capable to operate according to local laws or particular environmental conditions. The final aim is to improve performance and efficiency in terms of safety, quality and costs by providing common guidelines in all domestic assets in Romania where OMV Petrom operates to all personnel involved in Workover activities. The approach to WO has to be interdisciplinary, involving Drilling, Completion, Reservoir and Petroleum Production Engineering. This is vital in order to perform WO operation successfully and to obtain as much as possible incremental oil and gas production by utilizing the recommended best practices. This WO BP will guide the engineers and technicians of varies disciplines through the process with the objectives of helping them make the key decisions and obtain the optimum design to maximize productivity and, hence a profit. Many of the decisions made by the various disciplines are interrelated and impact the decisions made by other disciplines. For instance, the decision about the WO sequences and required technology may subsequently be changed due to the availability of well servicing and/or workover techniques, as well as by constraints caused by reservoir and well condition.

This provides a system of ongoing workover optimization to suit changing conditions, increased knowledge of the field and incorporate new technologies.

OMV Petrom Exploration Production RO-EP-DA-PO-06-POL-001-02 OMV Petrom Workover Best Practices Revision 1 2012


1-2 http://www.petrom.com

1.2 Contents

1.2.1 Source of Information

The information contained in this manual has been collected from many different sources. These include: Petrom OMV workover technical programs, standards, procedures, working instructions workover, completion and production manuals, Service companies manuals and catalogues and field oil industry recognized standards (API, ISO, etc.) and other sources.

1.2.2 Ownership

OMV Petrom is the sole owner of the information in this document. Any alterations or future updates of Workover Best Practices shall be done only OMV Petrom Exploration and Production staff.

Internal Project team resources are: 1. Domestic Assets (DA) HQ Production Operations departments.

Workover, Completion, Sand Control and Stimulation, and Production Optimization.

2. Workover/Well Intervention Business Unit (WO/WI BU) HQ. 3. Field experts from both DA Operation and WO/WI BU (Assets).

External engineering support is provided by consulting company CMS Prodex.

1.2.3 Confidentiality

The information in this document has been prepared for OMV Petrom and cannot be distributed outside the company. This document is the property of OMV Petrom and all rights are reserved. Neither the whole nor any part of this document may be reproduced, stored in any retrieval system or transmitted in any form or by any means (electronic, mechanical, reprographic, recording or otherwise) without the prior written consent of the copyright owner.

Hard copies of the Workover Best Practices will be distributed within OMV-Petrom DA Production Operations. Copy of the WO Best Practices Manual will be stored in electronic form on the OMV Petrom server for easy access

1.3 Updating, Amendment and Control

The Corporate Standards in this document define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual parties of the WO process to operate according to local laws or particular environmental conditions.

OMV Petrom Workover Best Practices has to be periodically updated to reflect changing field conditions, application of new technologies and techniques. Suggested changes should be forwarded for reviewing and inclusion in the next version of the document.


Revision 1 2012 OMV Petrom Workover Best Practices 2. WORKOVER BEST PRACTICES METHODOLOGY

2. WORKOVER BEST PRACTICES METHODOLOGY

Contents

2. WORKOVER BEST PRACTICES METHODOLOGY ................................................................................ 2-1

2.1 Introduction ............................................................................................................................. 2-1

2.2 Workover Process Definition and Description ......................................................................... 2-2

2.3 Workover Objectives and Functions ........................................................................................ 2-3

2.4 Workover Best Practices Methodology ................................................................................... 2-3

2.5 Workover Categorization in OMV Petrom ............................................................................... 2-4

List of Figures ....................................................................................................................................... 2-6

List of Tables ......................................................................................................................................... 2-6





2.1 Introduction

After a well is drilled to the final depth, the production casing and wellhead are set, cemented, and pressure tested.

Any subsequent operations for preparing well for long production life are referred to as well completion. However, changes might occur in the reservoir, nearwellbore zone and the completion equipment itself could be damaged. Therefore it becomes necessary to service or workover the well so to maintain/improve oil and gas production or performance of injection well.

Well workovers involve a wide variety of operations that often require a number of contractors, technical services, and suppliers working together at the wellsite. These operations must be planned and executed by qualified and competent people at all levels to ensure the safety of workers and public, protect the environment, and conserve natural resources. The well owner or assets conducting these operations have overall responsibility for achieving these goals. The wellsite supervisor plays a key role by directing and coordinating all workers at the wellsite to implement the planned workover activities, defined by the detailed technical program.

This document is focused on Workover Best Practices in OMV Petrom and explains why wells need workover and repairs, which technologies and techniques should be used and what benefits could be expected as a result of workover operation. It also gives the best practices for sequences of various WO categories and the well control equipment that is to be used for safe and reliable WO.

Numerous developed technology workflows bring at glance the best practices for each workover operations and direct a user through all phases of workover operations (well candidate selection, planning, execution, monitoring/real time control and postjob evaluation). The comprehensive workover process implemented in OMV Petrom is described in document Wells Operation and Maintenance Process of OMV Petrom E&P and ESP (C-06-01-E) and here is a briefly outlined workover system approach implemented in OMV Petrom (Figure 2-1).




Figure 2-1 WO process implemented in OMV-Petrom

2.2 Workover Process Definition and Description

The term workover refers to a variety of remedial operations performed on a well to maintain, restore, or improve productivity. Workover operations include such jobs as replacing damaged tubing, recompleting to a higher zone, acidizing nearwellbore damage, plugging and abandoning a zone, etc. The term well intervention refers to workover operations performed through the Christmas tree with the production tubing in place. Coiled tubing, small-diameter tubing, wireline, and snubbing work strings can be used for special technological operation requirements. Many of these operations are similar to those in workovers but are constrained by the internal diameter (ID) of the existing well completion.




2.3 Workover Objectives and Functions

Although there are various reasons for workovers, most of them can be grouped into six basic categories:

Repair or replace damaged equipment. Repair natural damage within the well. Recomplete to another zone. Increase production from an existing zone. Convert well from production to injection. Replace artificial-lift equipment.

2.4 Workover Best Practices Methodology

As shown in the Figure 2-2 below, the applied methodology for writing best practices consists of several steps:

WO process definition and description in OMV Petrom E&P and WO/WI BU (Assets)

WO types/categories Best Practice content definition Development of detailed technology workflows Downhole and surface equipment specifications dependent on well conditions Quality assurance and HSE requirements Technology and technical details and specifications

Figure 2-2 WO Best Practices Methodology




2.5 Workover Categorization in OMV Petrom

Based on previously mentioned reasons for workover, OMV Petrom has categorized all workover operations which have been used for writing ten various best practices. The table 2.1 show the main WO categories for which all required and systemized information have been collected and written as Best Practices document.

Table 2-1 WO Categorization

WO Category/Operation Subcategory

Well Control

Well Recompletion

Perforating

Technological Operations

Well Repair

Stimulation by

Acidizing

Stimulation by Fracturing




WO Category/Operation Subcategory

Sand Control

Zonal Isolation




List of Figures

Figure 2-1 WO process implemented in OMV-Petrom,

Figure 2-2 WO Best Practices Methodology.

List of Tables

Table 2-1 WO Categorization.


Revision 1 2012 OMV Petrom Workover Best Practices 3. RIG SPECIFICATIONS

3. RIG SPECIFICATIONS

Contents

3. RIG SPECIFICATIONS ......................................................................................................................... 3-1

3.1 Introduction ............................................................................................................................. 3-1

3.2 Overview of Workover Rigs Activities ...................................................................................... 3-1

3.3 Workover Rigs Data Sheets ...................................................................................................... 3-2

3.4 Selection of a Workover Rig ................................................................................................... 3-17

List of Figures ..................................................................................................................................... 3-19

List of Tables ....................................................................................................................................... 3-19





3.1 Introduction

An important factor influencing the overall cost and success of workover job is the proper choice of a workover rig to do the job. The primary objective of this WO best practice is to outline the most important factors impacting to allocate properly the available workover rigs according to the job specifications. Failure to utilize the proper rig even if operations are delayed several days, results in additional rig time, special tool rental and costly mistakes.

Currently, the total of 424 rigs, from which 337 are active and 87 inactive or temporally suspended, is deployed in OMV Petrom.

3.2 Overview of Workover Rigs Activities

WO rigs, WO Operations, number and durations of WO operations for 2011 are shown in charts below (Figure 3-1 and Figure 3-2). As it can be seen from the charts below the total number of workover operation were completed with available rigs is 1450. Almost 30% of the total operation belongs to recompletion of the wells. Around 20% of the operation belongs to category of others what could cause some problems in proper job planning and rig selection.

Figure 3-1 Number of Workovers by job Type




Figure 3-2 Number of Jobs per Rig and Job Type

3.3 Workover Rigs Data Sheets

During the life of the well, it becomes necessary at times to perform WO rig work that requires rig equipment to be operated near the designed limit. If this limit is exceeded, then the equipment is likely to fail thus causing financial loss and delays in the WO operations. It is common practice to review the rig equipment specifications in order to operate within its capabilities and limitations.

Each and every rig is supplied with different equipment. The main groups of components used for rig specification are:

1. General Information 2. Rig equipment 3. Rig power 4. Mud system & pump 5. BOP equipment (see Chapter 4. Well Control )

Important information about a rig is the depth limitation or capacity. Every piece of equipment has a maximum operating limit before failure occurs. In the case of the rig depth limitation, it is based on the load the derrick structure can sustain during operations. The limit is calculated based on the drill pipes and tubing (weight) to be run, additional equipment on the drill pipe, and the amount of over pull which might be needed in case of getting stuck. There are also safety factors included in the limitation to account for normal wear and tear.

The rig specification sheets are generated using currently available information and for these reasons, it is important to update the proposed specification data sheets in Tables from Table 3-1 to Table 3-14 every time the WO Best Practice is revised.




The complete specification, transport, rig-up, rig-down with detailed job procedures and safety regulation is written in document titled TRANSPORTUL, MONTAREA SI DEMONTAREA INSTALATILLOR DE LUCRU LA SONDA

This document has been issued by OMV Petrom EP WO &WI BU during 2011.

Table 3-1 WO Rig type TP 7.5 Specification




Table 3-2 WO Rig Type TP 10 Specification




Table 3-3 WO Rig Types EC 5 T/EL/ERT Specification




Table 3-4 WO Rig Type TW 30 Specification




Table 3-5 WO Rig type TW 32 Specification




Table 3-6 WO Rig Type TW 40 Specification




Table 3-7 Rig type TW 50 Specification




Table 3-8 WO Rig Type TD 80 Specification




Table 3-9 WO Rig type TW 100 Specification




Table 3-10 WO Rig type TD 125 Specification




Table 3-11 WO Rig Type AM 10 Specification




Table 3-12 WO Rig Type AM 12-50 Specification




Table 3-13 WO Rig type Rig 40 Specification




Table 3-14 WO Rig type AM 12-40 Specification




3.4 Selection of a Workover Rig

Conventional workover rig equipment has been specialized and refined so that it is a common practice to choose rig to fulfill all expected phases in accomplishing the integrated workover operations. The flexibility of the rig is required because it could easily be reallocated from one to another location in order to optimize time and costs of operations.

A number of factors will influence the selection of a workover rig including:

The nature of the operation to be conducted e.g. tubing size and hence the suspended weights of the tubing string, pressure control requirements for well re-entry, etc.

Depth or load capacity ( rig capacities are commonly spoken of in terms of depth rating with a particularly size and rig capacity is primarily depends on braking capacity, derrick capacity, and drawworks power

Logistical constraints - location of well, proximity to operating company base, availability, space on rig/platform, crane lift capacity.

Economics - cost, availability and its impact on deferred production. Reservoir characteristics (type of fluid, fluid contaminants e.g. H2S content, pressure,

temperature, fluid rate, depth of well etc.).

To use workover unit properly it is advisable:

To release one type of rig and move in another more suitable to accomplish the particular job at hand especially for land operations.

Avoid to use heavy-duty rigs to run small diameter tubing, Dont use heavy-duty production rigs on shallow wells.

Table 3-15 give practical recommendations how to choose workover rig properly considering the previous criteria and planned workover operations.




Table 3-15 Workover services




List of Figures

Figure 3-1 Number of Workovers by job Type,

Figure 3-2 Number of Jobs per Rig and Job Type.

List of Tables

Table 3-1 WO Rig type TP 7.5 Specification,

Table 3-2 WO Rig Type TP 10 Specification,

Table 3-3 WO Rig Types EC 5 T/EL/ERT Specification,

Table 3-4 WO Rig Type TW 30 Specification,

Table 3-5 WO Rig type TW 32 Specification,

Table 3-6 WO Rig Type TW 40 Specification,

Table 3-7 Rig type TW 50 Specification,

Table 3-8 WO Rig Type TD 80 Specification,

Table 3-9 WO Rig type TW 100 Specification,

Table 3-10 WO Rig type TD 125 Specification,

Table 3-11 WO Rig Type AM 10 Specification,

Table 3-12 WO Rig Type AM 12-50 Specification,

Table 3-13 WO Rig type Rig 40 Specification,

Table 3-14 WO Rig type AM 12-40 Specification,

Table 3-15 Workover services.


Revision 1 2012 OMV Petrom Workover Best Practices 4. WELL CONTROL

4. WELL CONTROL

Contents

EXECUTIVE SUMMARY ......................................................................................................................... 4-1

4. WELL CONTROL ................................................................................................................................ 4-3

4.1 Introduction ............................................................................................................................. 4-3

4.1.1 Well Control Description ................................................................................................... 4-3

4.2 Well Control Principles............................................................................................................. 4-3

4.2.1 Barrier Concept .................................................................................................................. 4-5

4.3 Well Control Methods/Procedures ........................................................................................ 4-10

4.3.1 Well Shut-in ..................................................................................................................... 4-10

4.3.2 Well Killing ....................................................................................................................... 4-13

4.3.3 Non Circulating methods (bullheading, constant tubing pressure method) ................ 4-19

4.3.4 Well Control Indications of Kicks ..................................................................................... 4-26

4.4 Downhole Equipment ............................................................................................................ 4-26

4.4.1 Special Equipment for Well Control ................................................................................ 4-26

4.5 Surface Equipment ................................................................................................................. 4-27

4.5.1 Wellhead and Christmas Tree .......................................................................................... 4-27

4.5.2 Blowout Preventers (types, selection) ............................................................................. 4-28

4.6 Workover Control Fluids ........................................................................................................ 4-38

4.6.1 Types of workover fluids used in Petrom OMV ............................................................... 4-38

4.6.2 Functions of WO Fluids .................................................................................................... 4-38

4.6.3 Workover Fluid Properties ............................................................................................... 4-39

4.6.4 Components of WO fluids ................................................................................................ 4-42

4.7 Well Control Workflow .......................................................................................................... 4-44

4.7.1 Well Control Best Practices Workflow Applied in OMV Petrom .................................... 4-44

4.7.2 Well Control Complications (Holes in Tubing, Reversing Gas Kicks, Problems with Circulating/Lost etc.) ....................................................................................................... 4-48

4.8 Quality and Safety Requirements for Well Control ............................................................... 4-50

4.8.1 Quality Control ................................................................................................................. 4-50

4.8.2 Safety Assurance .............................................................................................................. 4-53

4.8.3 Personnel Requirements ................................................................................................. 4-54

Appendix 4 A Physical Properties of Potassium Chloride .............................................................. 4-55


4. WELL CONTROL

Appendix 4 B Physical Properties of Sodium Chloride ................................................................... 4-57

Appendix 4 C Physical Properties of Calcium Chloride ................................................................... 4-59

Appendix 4 D Physical Properties of Ammonium Chloride ............................................................ 4-63

List of Figures ...................................................................................................................................... 4-64

List of Tables ....................................................................................................................................... 4-65

References .......................................................................................................................................... 4-66




EXECUTIVE SUMMARY

EXECUTIVE SUMMARY: 4. WELL CONTROL

No. Strongly Recommended

1. If pipe rams are used, make sure the string is at the height that avoids closing the pipe ram on a tool joint or tubing connection across the stack. This height should be known in advance.

2.

The number of barriers depend on well category (see Page 7).

3.

Shut in and secure the well, circulate at least one bottom-up volume of the well to check for the presence of gas in the workover fluid. This step will require running tubing to the bottom if it is not already there. If this is an open-hole completion, leave the work string inside the casing. If the well has been taking fluid, consider spotting a fluid loss pill across the suspect zone.

4.

If the well was shut-in, before reopening the well, follow steps below: 1. Check the tubing string pressure gauge by opening its needle valve. If no

pressure is registered on the gauge, check for flow past the safety valve. 2. Check the annulus pressure gauge. If no pressure is registered, check for annular

flow. Normally, you should check for flow through the choke manifold. 3. If there is no pressure or flow on either the tubing or the annulus, is it safe to

open the well? If there is pressure or flow, the well must be killed with the appropriate fluid and following the required procedure.

5. Kill workover fluid should be compatible with the formation and the formation fluids in order to prevent swelling of clays and scale deposition and other problems that can permanently block the perforations or greatly reduce productivity.

6. WO fluid should be in accordance with HSE regulation considering the potential impact of the presence of sour gases like H2S, CO2.

7. If a reverse circulation is used as a killing method, the well should be circulated holding a back pressure on the formation so that a constant bottom hole pressure can be maintained to eliminate any further flow of reservoir fluid.

8. Use volumetric method to manage gas when there is no tubing communication. Since tubing pressure cannot be read, the process must be controlled with the casing pressure and the volume of fluid bleed from the annulus.

9. Select the best killing method which fits the well conditions, use workflow on Page 27 (Figure 4-12)

10. All kicks should be treated as gas kicks until positive evidence shows otherwise.

11. The stab-in valve (with appropriate thread configuration & tested) must be always available on the rig flore (RF) while POOH or RIH with workstring.

12. Workover fluid weight needs to provide an overbalance at top perforations of 3,5 to 7 in order to protect the formation of excessive differential pressure and safe operations.


4. WELL CONTROL


EXECUTIVE SUMMARY: 4. WELL CONTROL

No. Not Recommended at All

1.

To start workover operation in an H2S area (or potentially H2S area) without a written H2S Emergency Response Plan (ERP) and if this site plan for shut-in and evacuation is not properly understood by Site Supervisor and company personnel prior to rigging up any equipment on location.

2. Do not allow any leaking of used barriers or used barriers which dont fulfil the standard of acceptable leak rate per API RP 14B and RP 14H for Xmas tree valves.

3. To continue with workover operation if the casing pressure decline. If this decline takes place, it is not allowed to continue the pump and the choke and shut in the well.

4. That duration of barrier pressure tests (the maximum anticipated pressure plus adequate safety factor), be shorter than 10 minutes. To use barriers if during test period of 10 minutes there is pressure decline.

5.

To use any completion and treatment equipment and associated safety systems if the equipment is not tested for functionality. Carry out the pressure test upstream of the choke below the maximum anticipated working pressure and full working pressure downstream of the chokes.




4. WELL CONTROL

4.1 Introduction

Well control is one of the most important considerations of those who complete and perform workovers on wells that are being drilled. Because of the increased awareness of the need to prevent injury of personnel and to save the environment, well control during workover operations is of particular concern in OMV Petrom SA. A proper, reliable and safe well control is the most important step as a part of complete workover process intended to prevent the hazard and uncontrolled flow of liquid and/or gas (blowout) during workover operations. The principal purpose of this chapter is to define the process for controlling wellhead events (kicks, leak or other adverse situation which could lead to blowout if uncontrolled) during well servicing activities in the OMV Petrom fields.

4.1.1 Well Control Description

Well control philosophy is to have pressure barriers that prevent uncontrolled flows of oil, gas or water to the surface or subsurface during workover operations. Barriers must be stand-alone and capable of acting independently, so that if one is removed the other is not affected.

During a workover the Well-Site Supervisor (WSS) and crew must contain the formation fluids within the formation while remedial work is being carried out. An undesired flow of these fluids into the wellbore is called a kick. If a kick fluid enters and moves up the wellbore, it has a tendency to expand and unload fluid above it. This may result in an uncontrolled and potentially dangerous flow of formation fluids from the wellbore. There are three main goals of well control:

Prevention of kicks by maintaining wellbore hydrostatic pressure at a level equal to or slightly greater than formation pressure (primary well control)

Early detection of kicks that do occur Initiation of corrective action to prevent kicks from developing into uncontrolled flow

Have always, ready to use, appropriate surface equipment on the rig floor, in case a kick occurs.

4.2 Well Control Principles

By applying the appropriate principles and calculations to the well control situation, the supervisor should be able to:

Interpret surface indicator data correctly. Eliminate small problems before they become bigger on the surface. Determine the controls needed to execute a workover kill operation. Choose the appropriate well control procedure for a given situation. Diagnose problems during well control procedures and take corrective action.


4. WELL CONTROL


Surface Indicators of Pressure

Tubing and casing pressure gauges indicates pressure at surface and make it possible to conclude what the downhole pressures are and how they change with time. These pressure readings can be used for well control calculations. Monitoring these pressures can help in preventing burst casing, formation damage, lost circulation, and other well control problems. It is important, therefore, that they be reported accurately and monitored carefully. Two important pressure indicators are the Shut-In Tubing Pressure (SITP) gauge and the Shut-In Casing Pressure (SICP) gauge.

The SITP gauge is connected to the bore of the tubing or work string. How you use the SITP reading depends on the circulation path that will be used to control the well. If the circulation is forward (down the tubing and up the annulus), then the well will be generally controlled over the long term with the tubing gauge. In addition to the SITP reading, the SICP reading will be used to assist in initially establishing circulation. Also, the SITP reading will be used to estimate pressure at the bottom of the well and to calculate the fluid weight needed to balance the well.

The SICP gauge is connected to the annulus. Again, using the SICP reading depends on the circulation path. If the circulation path is reverse (down the annulus and up the tubing), then the well will be controlled over the long term with the annulus gauge. During certain specialized well control procedures, the SICP gauge reading is used to control bottomhole pressure when fluid must be pumped into the top of the well or bled out of the well.

Friction Pressure and Principles

Understanding the meaning of friction pressure and its effect and well control are important for complete managing of the process. At any segment of the circulation fluid path some pressure drop will occur because of friction and pump has to generate energy to overcome friction pressure or pump pressure.

1. In a workover with typical completion geometry, 6595% of the friction is generated in the tubing and the remainder in the annulus. This is due to a higher fluid velocity inside the smaller tubing diameter compared with that in the larger annulus.

2. The total friction (and hence the pump pressure) does not change with the circulation path. Pump pressure will be the same whether forward circulating (down tubing, up annulus) or reverse circulating (down annulus, up tubing).

3. In reverse circulation, the friction pressure exerted on the formation perforations is equal to the total downstream resistance (i.e., the tubing friction). In forward circulation, the tubing friction pressure is expended by the time the fluid reaches the end of the tubing; it is not felt by the formation perforations.




Figure 4-1 Tubing/annulus friction pressure distribution

According to the first two principles, the indicated pump pressure is the same for both forward and reverse circulation (a sum total of 1,000 psi - 68.94bar, however, that the friction pressure exerted on the formation is considerably different). The formation is exposed to 750 psi (51.7 bar) friction pressure in reverse circulation, but only 200 psi (13.7 bar) in forward circulation, as shown in Figure 4-1. The WSS needs to be aware of this effect when choosing the circulation path. Although the pressure differential cannot be seen on the pump gauge (it reads the same in both cases), the effect is felt downhole. If the formation perforations are exposed, whole fluid may be pumped away or the formation fractured.

4.2.1 Barrier Concept

While a workover is in progress, physical barriers are necessary to prevent kicks because the usual controls and conditions that prevent kicks during drilling are absent. Workover conditions that differ from drilling conditions include the following:

Formations are more permeable since they have been perforated, stimulated, or hydraulically fractured.

Overbalanced conditions sustained in drilling are difficult to sustain in workover wellbores that contain open, permeable zones.

Workovers do not normally use a solids-laden fluid to deposit an impermeable filter cake, so the formation is more likely to take fluid, resulting in a loss of hydrostatic column height and possibly a loss of primary well control.

A barrier is defined as any impervious material or device that can be demonstrated to temporarily or permanently prevent the flow of wellbore and reservoir fluids. If fluid is considered to be a barrier, its hydrostatic pressure must be greater than the formation pressure and its condition and position must be capable of being monitored. Monitoring includes knowing the density of the fluid


4. WELL CONTROL


and the level of the fluid. The fluid level is most accurately determined by using acoustic level measuring with echometer.

Barriers are divided into the following classes:

Primary barriers are those used during normal workover operations. They include such tools as a wireline stuffing box or a workover fluid providing hydrostatic pressure.

Secondary barriers are used in support of normal operations or as a contingency (e.g. an annular preventer or back-pressure valve).

Tertiary barriers are used in emergenciese.g. a shear or blind ram or a tree master valve used to cut wireline.

Required numbers of barriers depend on the estimation of operation risk level, shown in Table 4-1. The proposed classification of the wells, considering a potential risk in well during operation, is:

LOW RISK WELL - Well that cannot flow to the surface naturally MEDIUM RISK WELL - Well capable of sustaining flow to the surface, or one with:

SIWHP less than 210 bar (3000 psi) H2S less than 1% (10,000 ppm)

HIGH RISK WELL - Gas well, or one with: SIWHP greater than 210 bar (3000 psi) H2S more than 1% (10,000 ppm)

See also classification for the: REGULAMENT PENTRU PREVENIREA SI COMBATEREA MANIFESTARILOR ERUPTIVE LA SONDELE IN FORAJ, REPARATII CAPITALE SI PRODUCTIE. Ed. 1982 Table 4-1 Number of barriers depend on well risk classification

Type of Well based on risk criteria Number of barriers Low 1 Medium 2 High 2 (Quality and standards of the barriers shall be

greater for high risk wells)

Detailed specification of required barriers in high risky wells is shown in Table 4-2 , Table 4-3 and Table 4-4.




Table 4-2 Minimum number of barriers on annulus and tubing/casing (high risk wells)

Risk Classification

Heavy lifting over wellhead

(i.e. move rig in/out)

Remove/Install BOP / XMAS TREE

Drilling / Workover Operations

High Risk Wells

Minimum 2 independent barriers



Surface barriers (separate for tubing and annulus side): Closed Xmas tree. Closed annular side outlet valves.

Surface barriers (separate for tubing and annulus side): Pressure tested tubing hanger seals + annular side outlet valves. Shallow set plug pressure tested from above to maximum anticipated working pressure differential. Liquid volume pumped shall be controlled to avoid testing against deeper plug. Shallow set and pressure tested. Retrievable Test, Treat and Stimulation (RTTS) packer (or equivalent) with storm valve.

Surface barriers: Pressure tested BOPs + Kelly cock or Gray valve + annular. (*) Pressure tested annular side outlets, casing / liner. (*) BOP stack shall be rated to a minimum of 350 Bar Shearing rams that can shear work string shall be included.

Subsurface barriers (separate for tubing and annulus side): Cemented and un-perforated casing +shoe track with floats or cement plug. Overbalanced static mud column. Overbalanced annular mud or brine column with partial losses, both with level at surface and continuously monitored. Inflow tested SSSV with zero leak rate and zero pressure above it. Tubing packer in combination with zero annulus pressure. Inflow tested downhole plug (shallow set) with zero pressure above it. Pressure tested deep or shallow set downhole plug with brine above it. (*) (*) Deep set plug and brine column are dependent and therefore considered one barrier.

Subsurface barriers (separate for tubing and annulus side): Cemented and un-perforated casing +shoe track with floats or cement plug. Overbalanced static mud column. Overbalanced mud or brine column with partial losses, both with level at surface and continuously monitored. Inflow tested SSSV. Pressure tested or inflow tested tubing packer in combination with zero annulus pressure and brine to surface. (*) Inflow tested bottom wireline plug. (Inflow test for 4hrs minimum). Pressure tested deep set plug with kill brine to surface. (*) (*) Deep set plug or completion packer and brine column are dependent and therefore considered one barrier.

Subsurface barriers: Over balanced mud or brine column, either static or with partial losses, which is continuously monitored and the level maintained at surface. Confirmed and pressure tested cement plug.


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Table 4-3 Minimum number of barriers on annulus and tubing/casing (medium risk wells)

Risk Classification





Medium Risk

Wells Or

Shallow sections of high risk wells where medium

risk criteria apply




Surface barriers (separate for tubing and annulus side): Closed Xmas tree. Closed annular side outlet valves. Inflow tested TWCV or BPV. Inflow tested shallow set wireline plug with pressure fully bled off above it. Subsurface barriers (separate for tubing and annulus side): Cemented and un-perforated casing +shoe track with floats or cement plug. Overbalanced static mud column. Overbalanced mud or brine fluid column with partial losses and continuously monitored zero surface pressure. (*) Dynamic water column, closely monitored and continuously filled up with specified minimum water rates. (relevant to annulus side). Pressure tested tubing packer. Pressure tested deep or shallow set downhole plug with brine above it. (**) (*) In case a Two Way Check Valve (TWCV) or Back Pressure Valve (BPV) is installed, only confirm pressure above TWCV /BPV is zero. (**) Deep set plug and brine column are dependent and therefore considered one barrier.

Barriers shall be combination of: Surface barrier: Pressure tested tubing hanger seals + Annular side outlet valves. Shallow set wireline plug or TWCV, pressure tested from above. Control the liquid volume pumped to avoid testing against deeper plug. Shallow set and pressure tested RTTS packer (or equivalent) with storm valve. Subsurface barriers: Cemented un-perforated casing + shoe track with floats or cement plug. Over balanced static mud column. Over balanced mud or brine column with partial losses, and continuously monitored zero surface pressure (relevant to annulus side). Dynamic water column closely monitored, and continuously filled up with specified minimum water rates (relevant to annulus side). Pressure tested tubing packer with brine to surface. (*) Inflow tested bottom wireline plug. Pressure tested deep set plug or shear out plug with kill brine to surface. (*) (*) Deep set plug or completion packer and brine column are dependent and therefore considered one barrier.

Barriers may be combination of one subsurface and one surface. Surface barriers: Pressure tested BOP + Kelly cock or Gray valve + annular side outlets. Pressure tested annular side outlets, casing / liner. Subsurface barriers: Over balanced mud or brine column, either static or partial losses, which is continuously monitored and level maintained at surface. Dynamic water column, closely monitored, and continuously filled up with specified minimum water rates. Confirmed and pressure tested cement plug. (*) Pressure tested at least to closed in Tubing Head Pressure (CITHP) + 10%.




Table 4-4 Minimum numbers of barriers on annulus and tubing /casing (low risk wells)

Risk Classification





Low Risk Wells

Or Shallow sections

of high or medium risk

wells where low risk criteria apply

Minimum 1 barrier Minimum 1 barrier 1 barrier

Surface barriers (separate for tubing and annulus side): Closed Xmas tree. Closed annular side outlet valves. Occasionally, gas broken out of the crude is present in the annul us of non free flowing wells. This gas shall be bullheaded back into the formation. Confirm that the pressure on the tubing and annulus is zero.

Shallow set and pressure tested RTTS packer (or equivalent) with storm valve. Cemented un-perforated casing +shoe track with floats or cement plug. Tubing side: Wireline plug or TWCV pressure tested from above. Annulus side: Pressure tested tubing hanger seals + Annular side outlets. Occasionally, gas broken out of the crude is present in the annul us of non free flowing wells. This gas shall be bullheaded back into the formation. Confirm that the pressure on the tubing and annulus is zero.

Drilling BOP or Sucker rod BOP + Kelly cock or Gray valve + annular side outlets. Confirmed and pressure tested cement plug.

Very often workover operation or well intervention will be performed in the wells having pressure at the bottom lower than hydrostatic pressure. In such situations there is no control over the fluid level because of continues losses of the workover fluid into formation. If the reservoir pressure and GOR are very low losing WO fluid is very intensive and the fluid level is close to the pump setting depth or bottom of the well. According to the OMV Petrom internal training and procedures (which are still under development), it could happen that during WO and WI there is no barrier in place.

Below are listed the operations in the wells during which for a particular period of time there is no barrier:

1. Change pipe rams manually or hydraulically (single ram preventer ) 2. POOH/RIH downhole equipment for different pump types (sucker rod pumps SRP,

progressive cavity pump- PCP and electrical submersible pump-ESP with downhole drive and cable).

3. Swabbing with a closed and open system (oil, water and gas wells without H2S). 4. Procedure for pull out of hole stuck sucker rod string and pump. 5. Change dual completion in oil wells with installed pumps and water wells (until now there

are now wells with dual completion and pump installed in OMV Petrom).

In all of these situations special precautions and procedures has to be used to assure safe operations. Development of these procedures is ongoing process and should be completed in the near future.


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4.3 Well Control Methods/Procedures

4.3.1 Well Shut-in

The importance of containing a kick and keeping the influx volume to a minimum cannot be overemphasized. Large kicks lead to high wellbore and surface pressures and large volumes of kick fluids that must be handled on the surface. The shut-in, or containment procedures can vary, depending on the type of equipment in use and the operation in progress at the time of the kick, whether on-bottom circulating or tripping. The shut-in procedures explained below apply to a conventional workover rig. Due to the limited wellbore volumes available in a completed well or one being worked over, it is imperative that minimal time be expended in shutting in a well.

Shut-in Procedure for Conventional Workover Rig (On-Bottom Circulating)

Initial lineup:

Killed BOP valves are closed. Path is open from BOP valves to choke. Choke is closed.

Use the following steps to shut in the well:

1. With pump(s) running, pick up work string until a tool joint is above the floor level. 2. Shut down pump(s) and watch for flow. 3. If the well is flowing, close the work string valve with its closing tool. This tool should be

stored in a conspicuous location on the rig floor. 4. Close annular BOP. If there is no annular BOP, use the pipe rams.* 5. Open the choke line valves on the stack to gain access to casing pressure. 6. Notify the WSS that the well is shut in. 7. Monitor and record SITP, SICP, and pit gain.

*If pipe rams are used, make sure the string is at a height that avoids closing the pipe ram on a tool joint or tubing connection across the stack. This height should be known in advance.

Shut-in Procedure for Conventional Workover Rig (Tripping)

Initial lineup:

Killed BOP valves are closed. Path is open from BOP valves to choke. Choke is closed. Work string safety valve and wrench are available on floor. Safety valve is in open position.

Check the well for flow; if it is flowing, use the following steps to shut in the well:

1. Position a connection for stabbing at rig floor. 2. Install an open work string safety valve. Close valve with a wrench. 3. Close annular BOP. If there is no annular BOP, use the pipe rams.*




4. If the work string is less than 900 m (3000 feet) long, or if there is a packer on the tubing string, space out the work string and close and lock a pipe ram.**

5. Open the choke line valves on the stack to gain access to casing pressure. 6. Notify the WSS that the well is shut in. 7. Read and record SITP, SICP, and pit gain.

*If pipe rams are used, make sure the string is at a height that avoids closing the pipe ram on a tool joint or tubing connection across the stack. This height should be known in advance.

**Locking the pipe ram resists the force of the wellbore pressure as it attempts to eject the string from the well.

Procedure for Shutting In Well

If the workover operation should stop from any reason, a well has to be shut in before the stopping operation

The following steps to shut in and secure the well should be followed:

1. Circulate at least one bottom-up volume of the well to check for the presence of gas in the workover fluid. This step will require running tubing to the bottom if it is not already there. If this is an open-hole completion, leave the work string inside the casing. If the well has been taking fluid, consider spotting a fluid loss pill across the suspect zone.

2. Make up a pup joint on the top of the tubing string. Lower the string, close the pipe rams on the pup joint, and lock the pipe rams. (The pup joint collar below the rams will prevent upward movement of the tubing string in the presence of unforeseen well pressure that might build during the closing period).

3. Install the tubing safety valve and a pressure gauge on top of the pup joint. (This gauge and valve allow you to make a safely check for pressure after the starting operation).

4. Close the safety valve. 5. Consider securing the tubing string with a chain and binder or other suitable device to

prevent further upward movement.

Procedure for Opening Well

It is not uncommon for a gas bubble to enter the wellbore during shut-in period. During the long time period, a slow feed- in of gas can accumulate into a sizeable volume. When the well opens, a pressure release and the flow will be achieved.

Follow these steps before reopening the well for normal workover operations:

4. Check the tubing string pressure gauge by opening its needle valve. If no pressure is registered on the gauge, check for flow past the safety valve.

5. Check the annulus pressure gauge. If no pressure is registered, check for annular flow. Normally, you should check for flow through the choke manifold.

6. If there is no pressure or flow on either the tubing or the annulus, is it safe to open the well? If there is pressure or flow, the well must be killed with the appropriate fluid and following the required procedure.


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Trapped Pressure at Shut-in

When shut-in pressures are initially recorded following the initial buildup, it is important to determine whether these pressures are accuratethat is, whether they are representative of the differential between formation pressure and wellbore hydrostatic pressure. Complications such as trapped pump pressure and rapid gas migration can affect their accuracy.

The following procedures can be used to detect the presence of trapped pressure and to remedy the situation if any is found. Perform this trapped pressure check only after surface pressures have been stabilized (after an initial period of rapid buildup).

Procedure for Checking for Trapped Pressure

Use the following procedure with the graphs in Figure 4-2. Bleed a small amount of fluid through the choke 40 to 75 lit (1/4 to 1/2 bbl). Surface pressures will initially decrease, build, and then stabilize.

Observe shut in tubing pressure (SITP). If the SITP is stabilized at a value less than the previously observed stable pressure and trapped pressure was detected and at least partially bled off, continue with the procedure.

Bleed another small amount of fluid through the choke and once again observe the stabilized SITP. Accurate SITP is verified when consecutive and identical values appear on the tubing gauge. In a workover, the SITP will often bleed to zero pressure.

Figure 4-2 and Figure 4-3 provide graphic representations of the bleeding process and accompanying SITP and SICP readings.

Figure 4-2 Pressure profile during bleeding with mechanically induced kick

Figure 4-2 shows the bleeding process when the crew handles a mechanically induced kick (i.e., a kick induced by not keeping the hole full during trips, swabbing, etc.). It is common that in many workovers and completions, when the SITP bleeds to zero pressure, the density of the fluid in the hole is sufficient to balance formation pressure.




Figure 4-3 Pressure profile during bleeding with light fluid in the hole

In Figure 4-3 the SITP did not bleed to 0 psi, presenting clear evidence that the fluid in the hole is lighter than required. Although rare, this can occur when light fluid is pumped into the well, creating a reduction in overall hydrostatic pressure and causing a kick.

Procedure for Obtaining the SITP with a Back Pressure Valve in the String

It is quite common that the SITP cannot be read due to the presence of a Back-Pressure Valve (BPV) or check valve in the work string, as a common practice in workovers. Nevertheless, an accurate reading is required to calculate the kill fluid density, ICP (Initial Calculating Pressure), etc.

The following procedure should be used to open the pump valve and determine the SITP:

1. Line up the manifold to pump into the tubing and monitor the gauge. 2. Slowly pump into the tubing (e.g., at a rate of 1/4 to 1/2 bpm); the pressure will increase.

When the BPV first opens, the pressure will stop rising momentarily (the gauge needle stutters or hesitates).

3. Record the exact SITP pressure reading when the gauge needle hesitates.

To continue pumping at this point will further increase the pressure and would be of no use. If there is a computer logging service on location, request a plot of pump pressure versus strokes. It is easy to see the pressure stabilization point on a graph (it looks very similar to the breakover point in the leak-off test done in drilling).

4.3.2 Well Killing

The choice of well kill procedure will depend on a number of factors including tubing and casing integrity, ability to circulate the annulus fluid, formation pressure and the well completion method. When it is required to kill a well during workover operation, the easiest, the quickest and the most certain method is by a circulation. This requires that there are some means of establishing communication as close to the producing zone as possible. This might be by opening a Sliding Side


4. WELL CONTROL


Door (SSD) just above the packer (or punching a hole in the tubing, or pulling a dummy from a Side Pocket Mandrel (SPM) in a completion or by using a string of pipe that has been run to a suitable (deep) depth using Coiled Tubing or Snubbing.

In this case, the method of killing the well is to circulate (forward or reverse) a kill weight fluid around the wellbore whilst maintaining a constant Bottom Hole Pressure (BHP) at all times sufficient to give a slight overbalance against the formation pressure. This is achieved by opening or closing a surface choke, and by following a pre-calculated kill sheet which gives the required tubing surface pressure at all times during the kill. The principles for working out the kill sheet are the same whether it is forward or reverse circulation.

Various factors must be taken into account when calculating a kill sheet (or graph).

Is the tubing used the same ID/OD for the whole length? Weight of fluid currently in tubing and annulus and weight of kill fluid? Current shut in WHP and annulus pressure? Contents of wellbore, oil or gas?

Well killing methods used in OMV Petrom are:

Bullheading Direct Circulation Reverse Circulation Intermittent Bullheading Using Lubricator Facility

Typical kill workover fluids might include:

Brine Completion fluid Drilling mud (oil or water based).

It is very important that the kill workover fluid is compatible with the formation and the formation fluids. Incompatible fluids can cause swelling of clays and chalks, scale deposition and other problems that can permanently block the perforations or greatly reduce productivity. Because of that OMV Petrom procedure for selecting the best workover fluid is based on the following principles:

Workover fluid must fit producing fluids (oil, gas and water) and used production/lift methods (flowing and AL).

Should be compatible with reservoir fluid and rock in order to avoid potential damage during workover operation (induced damage which will cause additional costs)

Impact of reservoir/wellbore pressure and temperature on WO fluid density and its changes during operation and execution of job.

WO fluid should be in accordance with HSE regulation considering the potential impact of the presence of sour gases like H2S, CO2.

Environmental protection is followed in accordance with government law regulations.




Wait-and-Weight Method

This method is most frequently used during drilling operation, but can be used to control well in workover well control.

The name of the method is indicative of what happensit should wait until the fluid is weighted up to the correct density and then kill the well. Whether the fluid density should be increased is determined by the stable SITP reading. If the SITP does not bleed to 0 bar, then the fluid density is insufficient and must be weighted up. The density can become insufficient for the following reasons:

Mismanagement of the fluid on the surface, resulting in light fluid being pumped downhole.

Formation fluid contamination of the fluid in the tubing. Penetration of a zone of higher formation pressure, as when sidetracking or washing

through sand plugs.

The wait-and-weight method is a one-circulation kill procedure. Kill fluid is pumped in while the influx is circulated out. If it is performed properly, it will require the least amount of on choke time. A drawback to this method is the time required to weight up and condition the fluid before the pumping begins. In the event of a gas influx, the time required to condition and weight up may allow gas migration to take place, requiring surface pressure monitoring and controlled bleeding of fluid until the actual well killing operation can begin.

Additionally, the Well Site Supervisor (WSS) must generate a circulating pressure schedule and use it to monitor the tubing pressure while displacing the tubing string. Tubing pressure will gradually decrease as the tubing string is displaced to kill fluidthat is, filled with kill weight fluid. This decrease in tubing pressure is the result of kill fluid hydrostatic pressure replacing the original underbalance shown on the tubing gauge.

Forward circulation

In a forward circulation, kill fluid is pumped down the tubing, through a circulating device (or out the end of a workstring/coiled tubing) and up the annulus. Forward circulation has several disadvantages over reverse circulation and is not recommended because:

It involves higher circulation pressures Disposal of formation fluids through the side outlet valves is difficult. It is more difficult to pump the oil/gas ahead of the kill fluid. The fluid in the wellbore will probably mix with fluid in the annulus making choke

operation more difficult. The casing will be exposed to corrosive wellbore fluids.

Under normal circumstances, a forward circulation kill would probably only be undertaken with a Coiled Tubing or Snubbing string in the hole.

The graph below (Figure 4-4) represents the typical pressure at the top of the Coiled Tubing or Snubbing string (tubing pressure) and at the top of the pipe/completion annulus (annulus pressure). These graphs are rather simplistic and assume various things;


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The sizes of the workstring and completion do not vary from top to bottom. The workstring is already full of the kill weight fluid. The well is not approaching horizontal. The well contains oil and gas. There is no gas invasion of the kill fluid as it comes up the annulus.

Figure 4-4 Forward circulation tubing pressure

Reverse circulation

The reverse circulation is the simplest and the safest kill method. It uses the natural U tube effect of the different gravities of fluids in the tubing and annulus to flow the well fluids up through the tubing and out through the Xmas tree choke. The only pumping required is during equalization across the circulation device before it is opened and when the kill fluid is in near balance with the other fluids in the tubing.

In a reverse circulation kill, the well is circulated holding a back pressure on the formation so that a constant bottom hole pressure can be maintained to eliminate any further flow of reservoir fluid. This procedure is even more effective if a plug can be set to isolate completion fluids and kill fluids from the formation.

As kill fluid enters the completion, there is a probability that gas will be encouraged to enter the kill fluid as it is being pumped up the completion. This can be minimized by adding viscosifiers to the kill fluid to inhibit the entrapment of gas.

This is normally the preferred method of killing a well when communication can be established at a suitable depth between the tubing and annulus. It has the great advantage of filling the tubing and annulus with kill fluid in one operation and all wells can be killed using this method.

When calculating the kill graph for a reverse circulation method, it must be remembered that the completion annulus already has a full column of fluid. This fluid may or may not be at a higher density than the kill fluid, as shown in Figure 4-5, Figure 4-6, Figure 4-7 and Figure 4-8.




The following graphs represent typical annulus and completion surface pressures during a reverse circulation kill.

They assume:

constant completion geometry, no gas invasion, deviation is not approaching the horizontal.

The following graphs also assume that the annular volume is greater than the tubing volume and that the new kill fluid is lighter than the existing completion fluid. This might happen in an old well where the original, kill weight, completion fluid is now too heavy for the depleted reservoir.

The graphs have been drawn with the zero psi lines above the axis to allow them to be seen.

Figure 4-5 Reverse circulation kill graph

Figure 4-6 Reverse circulation tubing pressure kill fluid is heavier than completion fluid


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Figure 4-7 Reverse circulation annulus pressure kill fluid is heavier than completion fluid

Figure 4-8 Reverse circulation kill fluid is approximately equal to completion fluid

Lubricate and Bleed

This method is recommended in wells where the other methods are not possible. The technique consists of pumping a small volume of very dense fluid down the string until the maximum allowable surface pressure is reached. Operations are stopped for a period of time to permit the dense fluid to fall. The well is then opened and the production fluids and/or gas are bled off until some of the dense fluid is recovered. The process is repeated until the entire tubing volume is displaced with the dense fluid and the well is dead.




4.3.3 Non Circulating methods (bullheading, constant tubing pressure method)

Bullheading

Bullheading (or squeeze killing) involves pumping kill weight fluid down the tubing and forcing the wellbore fluids back into the formation through the perforations. This method is only possible if the well conditions are such that pumping back into the formation is possible. If the tubing or perforations are blocked then this method cannot be used.

The pumping rate during bullheading must be high enough to stop any gas migrating back up through the kill fluid and to keep the fluid from free falling down the tubing and mixing with the wellbore fluids. Ideally, a workover fluid should be forced down the tubing, pushing everything in front of it.

The pump rate (and pressure) must not exceed formation fracture pressure. Fracturing the formation can cause severe losses that are very difficult to stop even with coarse Lost Circulation Material (LCM). Pressure ratings of surface equipment must also be considered.

Most producing wells in OMV Petrom have low formation pressures and a full column of kill fluid may give rise to excessive bottom-hole pressures which may cause a fluid to be lost into the formation. In this case, solids such as sized salt particles or Calcium Carbonate etc. may be required to temporarily block off the perforations to enable them to support the full column of kill fluid.

In low permeability wells it might be difficult to pump fluids into the formation. This can result in very high surface pressures for low pump rates.

Small tubing strings may also cause pressure problems because of high friction losses in the tubing. If the tubing is very large, pressure will probably not be a problem although it may be difficult to maintain the clear interface between the kill fluids and the wellbore fluids. This can cause the kill to take much longer with much more fluid lost to the formation.

The main disadvantage of bullheading is that everything that is in the wellbore, including scale, debris, sand, etc., is likely to be forced back into the formation. There is even the risk of plugging the perforations before the kill is achieved. Surface and downhole pressures will be the highest with bullheading.

The bullheading kill sheet template used as best practice in OMV Petrom is shown in Figure 4-9.

Procedures for Controlling Gas Migration

The two modes of gas behavior in the wellbore exist: gas expansion, where gas is free to expand normally (as it does in constant bottomhole pressure kill procedures), and gas migration, where gas migrates up a shut-in or blocked wellbore and does not or cannot expand.

There are two recognized methods of dealing with migration, or allowing expansion: the constant tubing pressure method and the volumetric method. These methods are used to control gas migration when it is not possible to circulate or bullhead the well. They can be used temporarily while operations are ongoing to get in a position where the well can be circulated or bullheaded.


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Figure 4-9 Bullheading Kill sheet template

Constant Tubing Pressure Method




The constant tubing is based on the following assumptions: 1. There is communication between the tubing and the choke located on the annulus. 2. The tubing pressure can be read.

This procedure can be used to control gas migration while mixing the kill fluid or making other preparations for a circulating kill procedure.

Procedure for Constant Tubing Pressure Bleed Method: 1. Allow SITP to increase by a safety margin of 3.5 7 bars (50-100 psi), which prevents further

influx due to over bleeding with choke. This is called the lower limit. 2. Allow SITP to increase additional 3.5 7 bars. This is the upper limit. 3. Using the choke, bleed the annulus until the tubing pressure drops down to the lower limit.

The time lag should be marked. 4. Repeat steps 2 and 3, keeping the tubing pressure between the lower and upper limits as

long as desired or until another procedure is implemented.

Important Note: There is a time lag between opening the choke and seeing the pressure drop on the tubing gauge. The recommended procedure is to open the choke until the desired drop is seen on the casing gauge, then close the choke and wait until the change appears on the tubing gauge.

In the long term, the casing gauge reading will not stay constant the way the tubing gauge does (the WSS should not use the choke to make it so!). With successive bleed cycles, the gas is continually expanding as it rises up the annulus.

Volumetric Method

This procedure accomplishes the same objective as the constant tubing pressure method in allowing gas expansion, but it uses a different process control. This method is used when there is no tubing communication. Since tubing pressure cannot be read, the process must be controlled with the casing pressure and the volume of fluid bleed from the annulus. There must be a calibrated tank on the rig located downstream of the choke capable of reading of small volume increments - 80 lit (1/2 bbl).

Procedure for Volumetric Method

1. Select a safety margin and a range. Recommended margin: 7 bars (100 psi). 2. Calculate Hydrostatic Pressure (HP) per fluid volume in the upper annulus (bar/m3).

HP (bar/m3) = Fluid Gradient (bar/m)/Annular Capacity Factor (m3/m)

3. Calculate Volume to Bleed each cycle.

Volume to bleed (m3/cycle) = Range (bar)/HP(bar/m3)

4. Construct casing pressure vs. volume to bleed schedule. 5. Allow SICP to increase by margin without bleeding. 6. Allow SICP to increase by range without bleeding. 7. Maintaining SICP, bleed small volumes of fluid into tank until calculated volume in step 3 is

bled. Repeat steps 6 and 7 until gas is at surface or another procedure implemented.


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During the procedure, it is critical to hold SICP constant while bleeding fluid. The bleeding is done on the flat part of the pressure graphthat is, the SICP is not to increase or decrease. The choke should not be opened more to speed up the bleeding process (which lowers SICP below the line) or another kick will result. Patience is required: the bleed for the first volume may take several hours (depending on well depth and type of wellbore fluid).

The question often arises, How long should this procedure be carried on? Remember that the goal is to control gas migration and allow expansion. If the gas influx reaches the top of the well during the volumetric schedule, the procedure is over: gas migration has been controlled. (This is evidenced by the sound of gas flowing across the choke and a stable SICP when the well is closed in.)

Do not open the choke at this point and bleed gas off the well. This will reduce bottomhole pressure and most likely result in additional influx. It will then be necessary to create yet another pressure schedule and repeat this rather time consuming procedure. Removing gas from the top of a well (at constant BHP) requires lubricate-and-bleed procedures.

Volumetric kill sheet template is shown in Figure 4-10.

Figure 4-10 Kill Fluid Volume Calculation sheet




In Figure 4-11 is shown workflow for selection the well killing method depending on downhole and surface pressure and fluid inflow conditions.

Figure 4-11 Technology Workflow for Selection Well Killing Method

WELBORE PRESSURE CONTROL

Pressure equilibrium in the wellbore and arround it

Ppores Pwellbore Pfrac

Lost of circulationPwellbore>Pfrack

Kick indicatorsPpores > Pwellbore

Prevent the kick

Control the kick

Not controllable

kicks

Controllable kicks

Control Influx without flowing it out of wellbore

Control influx out of wellbore

Force fluid back to

formation

Control influx at surface

With circulationWithout circulation

By pumping non-weighted fluid (drillers

method)

By pumping weighted fluid in one stage

(wait and weight method)

By pumping weighted fluid

in several stages

By pumping weighted fluid

while circulating

(simultaneous method)

Volumetric method

Bull heading method

Lubrication method


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International kill sheet step by step procedure in Figure 4-12 is accepted and used in OMV Petrom as best practice.

Figure 4-12 Surface BOP vertical well kill sheet




Figure 4-13 Surface BOP vertical well kill sheet (continuation)


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4.3.4 Well Control Indications of Kicks

Understanding the causes and warning indications of kicks can help the WSS and crew prevent them from occurring or, if they do occur, at least minimize their effect. Most kicks can be eliminated safely and effectively if the WSS and crew monitor operations carefully and understand the necessary actions that should be taken in the event of a kick. The best option, however, is preventing kicks. Knowing what causes an influx of undesired well fluids into the wellbore is the first step in preventing kicks. Known causes of kicks

Documents

Workover Best Practices