With regards to the major catastrophic incident, BP Deep Water Macondo which happened on 20 April 2010, many companies in the oil and gas industry tend to heavily invest in extra Health, Safety and Environment (HSE) programs in order to raise the HSE awareness and standard for their employees. These non-compulsory HSE plans have been introduced into a company in different ways such as in-house initiatives and third party HSE training services. For many years, the price of oil was slightly above 100 $/bbl and the spending extra budget on safety programs was an acceptable practice across the industry. Therefore, the budget at HSE has increased dramatically over this period of time.

However, since mid-2014, the oil price has drastically dropped from about 110$/bbl to 50$/bbl as of October 2016. Most companies in the upstream business have had extremely bad effects on their incomes; they therefore have looked into ways to reduce operating expenditures without compensating their reputation, safety, reliability, and product quality and harming their people. One aspect to help corporations achieve this goal is to optimize the HSE practices.

 

There are 5 main areas that a company should implement in order to optimize HSE practices.

1.  Clearly Communicate Objectives of HSE Optimization to Employees and Set Goals

Due to the oil price slump, companies need to make efforts in cost cutting. It is important to set objectives for the organization and communicate them to everybody. The upper managements need to clearly state their vision, their expectations, and the ways that each and every employee can help cost saving. Once decision is reached that HSE optimization is one area that a company needs to focus, managements may have a meeting with employees to clearly communicate to employees why a company need to do, what a company plan to do, when the plans will start, how this will affect employees, etc. Clear communication can help emphasize the importance of the plan and make employees fully aware and prepare for future change.

After employees acknowledge the company’s goal, managements should encourage employees to set their goals to align with the company’s to support the HSE optimization. The alignment of employees’ and their companies’ goals is also important because it will ensure that certain results are reached by the end of the year. The process of goal setting is also an opportunity to encourage employees to bring their thoughts to support the HSE optimization program, and it is crucial to conduct at the first step because it can eliminate any confusions or rumours which may have negative effects on both workplace morale and company performance.

2.  Identify Required HSE Policies

A company should identify which HSE policies and/or procedures are essential to the operation. Two parts of HSE are HSE policies at a company level and at a specific department level. They must be classified their essentials to a company. Managements may consider forming teams that consist of experienced people in several backgrounds such as managements, engineers, safety officers, and field personnel to help review the company’s policies and verify which HSE policies are necessary. Then, these teams can utilize their expertise to decide what area is needed or not needed and revise its HSE policies. It is very important that experts in teams should hold different backgrounds to give diverse perspectives about the policies, helping to come to the right decision.

3.  Simplify HES Procedures and Workflows

Simplifying HSE processes and workflows is one of the main critical areas to create high efficiency processes and reduce repetitive workflows. Over time, many HSE programs become more complicated to understand and follow. The over complex HSE workflows can make people confused or feel frustrated and sometimes require employees to do many paperworks to ensure the compliance with company procedures instead of starting to perform operation, resulting in ineffective works.

There are several methods that can be applied to simplify processes. One is Lean Six Sigma, a process improvement methodology relying on a team effort to improve product quality and remove waste in the process . This methodology consists of five steps for improvement which are Define, Measure, Analyse, Improve, and Control. These five core steps will help reduce waste and determine improvement opportunity in HSE processes. The scale of Lean Six Sigma may be small or big depending on how complicate the company HSE policies are. However, the most vital point to successfully perform the process is to have teams of experienced employees to execute these tasks because the process cannot be improved if people do not understand it. The simplified HSE procedures are easy for employees to understand, save time on workflows, and provide more time to focus on their tasks at hand. The companies will also benefit from other value-added activities created from spare time left from paperworks.

4.  Maintain Good Training Programs

Maintaining high-quality training programs helps employees fully understand of all aspects of safety related to the jobs. Lack of training can lead to severe results in a high risk operating environment in oil and gas industry. However, some training programs should be evaluated to ensure whether they are suitable for people in particular jobs, or they are too general and not applicable to relevant tasks. A company may classify this topic as a non mandatory course because the content may not be used in the near future, and the crews will eventually forget what they have been trained. As a result, unnecessary training can be costly with little benefit to a company and employees. Following are three aspects of training programs that the company may incorporate in its plan to save cost while maintaining high standard of training programs.

4.1      Identify What Needs to Be Taught

Determining training requirements for each job function is a key because each job function requires different areas of training to be able to efficiently perform its tasks in a safety manner. HSE training should include both safety and technical aspects. For instance, all offshore facility operators are required to train the Basic Offshore Safety Induction and Emergency Training (BOSIET), but personnel in a procurement department are not because the procurement staffs are in the office and rarely have a chance to perform offshore safety and emergency situation. Hence, each department should develop its training need analysis that tailors to specific department, ensuring that employees have all necessary technical knowledge for their jobs. Furthermore, a company needs to integrate local regulation or requirements into the analysis because each country has different legal requirements on how many mandatory training courses which employers must provide to their staff members.

Once the training requirements are identified for each job function, it is imperative to compare them with existing training programs to determine what inessential training is. Then, a company should consider cancel all non-compulsory training to save operating costs.

4.2      Make Training Relevant to The Operation

The effective training must include real task examples which directly relate to personnel in a training session. Nonetheless, regularly, HSE training courses convey both safety and technical contents that are too generic and lack relevant examples to help employees relate to their experience and obtain more understanding in the topic, resulting in inefficient training. Furthermore, interactive training sessions that include specific case study instead of only lectures benefit employees. This can be done by having discussion sessions which are relevant to a working background of workforce integrated into classes.

Making the HSE trainings relevant to the workforce will save a lot of time and a budget to a company because the employees will learn what they need and be able to apply knowledge to their tasks. Therefore, no extra trainings are required to have the employees study irrelevant subjects to their work and no extra budgets spent for the non-essential training classes.

4.3      In-House Training

Some outsourcing classes are expensive and may not meet a company’s HSE requirement, so this area can be optimized by substituting with some in-house training. With the low oil price situation, there will be fewer activities in oil and gas industry. Therefore, some of experienced personnel will be free from the busy period. A company should take this opportunity to train some of fully skilled employees to be next trainers so that there will be no extra cost to hire new trainers in the future. Following are some advantages of in-house training. Firstly, the company can save budgets such as travelling and accommodation cost, and training cost from outsourcing. Secondly, in-house trainings can be more effective than outsource programs because in-house programs can be specifically designed to serve a specific location and use real work cases from the company. Finally, the company will be able to retain knowledge and experience within the organization and maintain excellent quality training to current teams.

5.  Optimize Cost of Safety Equipment

Safety equipment is one area that should be optimized because several safety initiatives have introduced new model of safety equipment into work places. Previously, people had a tendency to buy new safety equipment because new tools were assumed be better tools. This is possibly valid; however, the company eventually has several models of safety equipment which have similar functionality in a stock. Single item of safety gear does not cost much when compared to other operating budgets. Unfortunately, when costs of many safety tools are added into a workplace, this ultimately becomes a substantial hidden cost piling up in company’s expenses.

To optimize the safety equipment cost, a company may consider some recommended steps listed below;

1. Identify what is needed – experienced groups of employees investigate what types of equipment are in inventories and identify what essential safety kits a company should hold.

2. Establish a standard – a company should set standard operating procedures on what types and models of safety equipment are acceptable to use.

3. Utilize Information Technology (IT) – an inventory of safety equipment must be kept in computer database so that all inventories can be properly managed.

4. Deplete non standard equipment – all non-standard equipment will be used first to remove it from the stock.

5. Estimate what needs – once standards are established, each department must follow the standard and estimate how much equipment is required for each operation.

6. Purchase bulk volumes – when the quantities of safety gear needed is determined, a purchasing department can provide quotations to suppliers to get competitive prices. Cost per unit of HSE equipment will be decreased by applying this purchasing strategy.

7. Replenish only standard equipment – a company may utilize IT and computer data base to monitors the usage and level of safety equipment to replenish the inventory. The computer can automatically inform employees who are in change of a safety equipment inventory. Therefore, they can verify the stock and inform a procurement department to start a buying process again.

Conclusions

Due to a down turn of oil and gas industry, many companies are not able to sustain high expenses on extra safety Health, Safety & Environmental (HSE) programs. Therefore, a good HSE optimization plan should be considered and implemented to continue high HSE standard and reduce excessive spending. Five recommended optimization plans that should help a company to reach their goal are as follows;

1. Clearly Communicate The Objectives of HSE Optimization to Employees and Set Goals

2. Identify Required HSE Policies

3.  Simplify HES Procedures and Workflows

4.   Maintain Good Training Programs

5.  Optimize Cost of Safety Equipment

Referred Source – https://www.linkedin.com/pulse/how-should-company-plan-optimize-its-hse-practices-pongtepupathum?published=t

Saudi Arabia has the second largest oil reserves in the world, so it is quite logical that there are several successful oil companies in this country. One of them is Saudi Aramco or simply Aramco. With a revenue of around $380 billion and value between $2 trillion and $10 trillion, Saudi Aramco is the most valuable company in the world.

One of the reasons why this company is always on top is their investment in research and development of new oilfields. Manifa oilfield is one of these new oilfields that have proven to be a great investment.

Basic information

Manifa oilfield is located on a manmade island. Thanks to modern technology, engineers and architects can create artificial islands and make the production of oil much easier and simpler. Of course, in order for such manmade island to promise a good return on investment, it must be situated in shallow waters. Otherwise, it will need a lot of material to build it. At the same time, these manmade islands guarantee the improvement of long-term reservoir recovery. In addition, oilfields built on manmade islands allow the creation of more wells, don’t have negative environmental effects and it is much safer for the workers to work on an oilfield like this.

Manifa Field (Top View)

In the beginning, this project was known as the Manifa Arabian heavy crude program. Although this is an investment of Aramco, the authorities gave their support because it was part of the plan for the development of new Saudi oilfields that have allowed Saudi Arabia to boost oil production. It is estimated that the maximum capacity for oil production in Saudi Arabia is about 12.5 million barrels and Manifa provides a great contribution.

It is interesting that Manifa was discovered back in 1957 and the authorities have made basic preparation for oil exploitation, but the project was frozen because the crude had high quality. 40 years later, Saudi Aramco has started making plans for the so-called Manifa project. In 2007 the FEED (front-end engineering and design) was completed. Obviously, the investor was interested in completing this project as soon as possible, but although the initial construction project was signed by the end of 2007 and it was expected that the process of construction will start in the first months of 2008, there were some technical issues that postponed the start of this project. After two years of the planned start, in the first months of 2010, construction workers have started working on the Manifa oilfield.

This time, even though the production was planned for later, it started earlier in April 2013.  In July 2013, the oilfield produced about 500.000 barrels a day. Today, it produces 900.000 bpd of crude oil. The cost of this project is estimated at about $10 billion.

Additional information

Manifa oilfield is one of the largest oilfields in the world today. In addition to its ability to produce about 900.000 bpd of heavy crude oil with high quality, the Manifa project is known for its production of sour gas, gas condensate, and water.

Manifa oilfield

Crude stabilization units, separation facility, and additional separators are the components that make the processing infrastructure in this place. In the near future, it is expected for the Khursaniyah gas facility to be expanded in order to meet the needs for sour gas processing which are about 120 million cubic feet per day.

Manifa has four well-developed offshore and onshore pipeline networks and a top-notch supply system. This sophisticated water supply system allows Saudi Aramco to inject more than 1.3 million barrels of aquifer water in an oil reservoir per day in order to keep the needed pressure for getting the most from the production of crude oil. The majority of heavy oil is shipped directly to a new refinery located in Yanbu. This refinery makes oil low on sulfur for the US companies. Manifa includes more than 400 drilling islands, more than 10 offshore platforms and 15 onshore drill locations, injections facilities, water supply wells, numerous pipelines and heat, and electricity plant with a capacity of 420 MW. There is no doubt that this is one of the most advanced facilities dedicated to oil production (and more).

The Electrical Stability (ES) is one of the vital properties for oil based mud. It shows the voltage of the current flowing in the mud. The ES number represents the mud emulsion stability. The more ES is; the more the emulsion stability is.

Oil based fluid is a non-conductive material. Therefore, the base fluid will not transfer any current. Only the water phase in the mud will conduct the electricity. If the mud has good emulsion, you will have high ES figures. On the other hand, if the emulsion of the mud is bad, you will have low ES value.

The Electrical Stability (ES) is obtained from an electrical stability tester kit (see the image below).

Electrical Stability Meter

There are several factors that can weaken the emulsion, such as oil/water ratio, solid content, pressure, temperature, some types of weighting material, etc.

What the Electrical Stability (ES) will tell us?

If ES is lower than a normal mud specification, it indicates that there is something unusual in the mud such as water or salts, which will make emulsion of the oil based mud in bad shape. Moreover, the ES can be utilized to determine an interface between water and oil based mud while displacing water with oil based fluid.

For good drilling practices, it is required to frequently monitor the ES level and watch  for any unusual changes. Changes in the ES can be seen while drilling into green cement or while adding any conductive material as stated earlier. These known factors affecting the ES must be noted in order to prevent any confusion when interpreting the mud’s property.

References

Andy Philips, 2012. So You Want to be a Mud Engineer: An Introduction to Drilling Fluids Technology. Edition. CreateSpace Independent Publishing Platform.

Ryen Caenn, 2011. Composition and Properties of Drilling and Completion Fluids, Sixth Edition. 6 Edition. Gulf Professional Publishing.

For most of oil based mud, lime (Ca(OH)₂) is used in the system in order to perform a chemical reaction with fatty acid emulsifiers. Typically, 3 to 5 lb/bbl of lime is added in the drilling mud so that there is enough hydroxide (OH^-1) ions to keep the emulsion stability in  good shape.
Moreover, lime (Ca(OH)₂) will control acid gases such as H₂S and CO₂. The following chemical equations demonstrate how lime reacts with H₂S and CO₂, respectively.

Ca(OH)₂ + H₂S -> CaS + 2(H₂O)
Ca(OH)₂ + CO₂ -> CaCO₃ + H₂O

If drilling into zones where CO₂ or H₂S exists, the amount of excess lime should be increased to around 5 to 10 lb./bbl., because some lime is used for emulsion stability and others react with acid gases to maintain the mud’s properties.

What’s more, when the well is drilled into formations containing H₂S, the excess lime must be kept constantly at 5 to 10 lb/bbl all the time. Do not try to reduce the amount of excess lime because the chemical reaction between H₂S and lime is reversible. Therefore, if the level of excess lime is not maintained, the H₂S gas can be released at the surface from the reversible chemical process.

References

Andy Philips, 2012. So You Want to be a Mud Engineer: An Introduction to Drilling Fluids Technology. Edition. CreateSpace Independent Publishing Platform.

Ryen Caenn, 2011. Composition and Properties of Drilling and Completion Fluids, Sixth Edition. 6 Edition. Gulf Professional Publishing.

A number of components are fitted to the casing string to enable it to be cemented in place. In order to successfully cement each casing string, casing accessories should be installed and the necessary components are listed below;

Float Shoe

A float shoe is a short and rounded shape component with non-return value inside which is installed at the end of the casing. The advantages of a float shoe are as follows;

• Prevent mud flowing back while running casing and prevent cement from outside U-tubing back into casing due to unbalanced conditions while performing cementing operation.
• Help running casing to the well. The round shape of a float shoe prevents a casing string from hanging up and guiding a string into a wellbore. Some float shoes are made of high strength drillable material and can be used to reciprocate and rotate to pass any obstructions in a wellbore.

Float Shoe

Float Collar

A float collar is also a non-return valve which normally installed one or three joints above a float shoe. The advantages of a float collar are as listed below;

• Prevent mud and cement from U-tubing back into a casing string and float casing if required. This is the same advantage as a float shoe, and this also serves as a backup check valve in the casing string. If the check valve in a float shoe fails, a check valve in a float collar still performs the same purpose.
• Land cement wiper plug. Some models of float collars have non rotating profiles. A cement plug landed into the profile will have fewer tendencies to be spun while drilling out. This will minimize time to drill out cementing plug because a cement wiper plug will not be spanned.
• Contain contaminated cement. The space between a float shoe and float collar called a “shoe track” will contain any contaminated cement when the top plug wipes any residual mud inside the casing. This will prevent bad cement at a casing shoe and help operators to achieve good formation integrity test (FIT) or leak off test (LOT) of the next well section.

Float Collar

Centralizer

A centralizer is a device to keep a casing string out of the well bore wall. The advantages of casing centralizers are listed below;

• Centralize casing string and minimize contact between casing string and wellbore
• Achieve proper cement around casing string and reduce cement channelling
• Minimize differential sticking and drag while running in hole

Centralizer

Wire Scratcher

A wire scratcher is sometimes installed with casing string to help remove filter cake in the wellbore while a casing string is run in the hole. This will help improve cement bond quality.

Wire Scratcher (Ref: http://www.eneroiloffshore.com)

Numbers of centralizers and centralizer placement are very important parts to achieve casing running operation and get good cement jobs. Excessive casing jewelleries installed in the casing string can lead to an operational issue while running casing. Therefore, compromising the quantity of installed centralizers and jewelleries is imperative to meet all required objectives.

Referrences

Baker, R. (2001) A primer of oilwell drilling: A basic text of oil and gas drilling. 6th edn. Austin, TX: Petroleum Extension Service, Continuing & Extended Education, University of Texas at Austin.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

The Organization of the Petroleum Exporting Countries (OPEC) has agreed to cut supply by 1.2 million barrels per day (bpd) to 32.5 million barrels, the head of the organization announced.

Ahead of the official announcement, Bloomberg broke the news, quoting an unnamed delegate in Vienna. Crude prices soared more than 7 percent on the report. As of 16:29 GMT, Brent crude was trading at nearly $50 per barrel, while US crude benchmark WTI was above $48.

Calling the decision “historic,” the organization said the output cut would be in effect from January 1, 2017. The deal was reached after weeks of negotiations, as Saudi Arabia, Iraq and Iran fought for the very last barrel of production. This is the first coordinated cut from OPEC in eight years.

According to the new agreement, Saudi Arabia will reduce its production by 486,000 bpd, the official announced. Ministers of Iraq and Kuwait said their countries would reduce supplies by 209,000 bpd and 130,000 bpd respectively. Meanwhile, Indonesia has suspended its OPEC membership and is not taking part in the reduction. The agreement also expects non-OPEC countries to cut about 600,000 bpd. Russian Energy Minister Aleksandr Novak welcomed the OPEC decision, saying Moscow would contribute its part if the organization keeps to its commitments.

Mechanical properties of material are one of the most important basic concepts in a well design and this section will briefly discuss about key mechanical properties and their applications. Furthermore, there is a discussion about effect of corrosion on the mechanical performance of load carrying components.

Mechanical Properties of Material

Basic mechanical properties are as follows;

Hardness

Hardness is a resistance of materials to permanent deformation and is sometimes referred to a resistance to abrasion or scratching. The greater of the hardness, the harder it is for the materials to deform. The application of hardness is to inspect if materials have been properly treated during a heat treatment process. The comparison between the actual hardness and the standard hardness of materials will show whether the current batch of material is proper and suitable for use or not.

Strength

Strength of material is an ability to work within a load without failure of the material. Tensile and yield strength are critical properties in terms of material strength.

Tensile Strength

Tensile strength or ultimate tensile strength is the maximum stress on an engineering stress-strain curve. At this point, materials are plastically deformed but they may not be broken apart yet depending on types of materials.

Yield Strength

Yield strength is a stress where a material starts to be in a plastic deformation region. Load applied to a material within yield strength will not permanently change a shape of material. Once the load is released, a material will come back to its original shape. However, if stress is more than yield strength, a material’s shape will be plastically deformed.

Determining yield strength from a stress-stain curve is not easy in many cases. Therefore, an offset yield point is usually defined as a practical standard. In order to find an offset yield point, it typically starts with 0.2% strain offset and then draws a parallel line to a stress-strain curve in the plastic region. An intercept point in a stress–strain curve with 0.2% strain offset is the offset yield point (Figure 1).

Figure 1 – Stress-Strain Curve

Elasticity & Plasticity

Elasticity is a material property to recover back to the original shape after stress is removed. On the other hand, plasticity happens when the applied stress exceeds yield stress of materials; thus, materials deform from the original shape permanently. When plotting a stress-strain curve, an elastic region is shown as a straight line and the ratio between stress and strain is called the Young Modulus of material. When stress is applied more than a yield point, the relationship between stress-strain does not behave as a straight line.

Toughness

Toughness is the ability of a material to absorb energy before it is fractured. A tough material such as mild steel requires a huge amount of energy to break it apart, whereas a brittle material such as glass cannot absorb a lot of energy. Additionally, temperature has a big impact on the toughness of material. Some materials are very tough in standard temperature conditions but become brittle when operating in very cold conditions.

Ductility & Brittleness

Ductility is the ability of materials to plastically deform before they fracture when tensile force is applied. Ductile materials have a large scale of deformation prior to breaking apart. Conversely, materials that can withstand little or no plastic deformation before being parted are called brittle materials. Temperature has a big effect on ductility of material. A high temperature will increase ductility of material, while a cold temperature will decrease ductility so a material will be more brittle.

Malleability

Malleability, which is a similar property to ductility, is the ability of solid materials to plastically deform by compressive force before they are fractured.

Effect of Corrosion on the Mechanical Performance

Corrosion damages both physical and mechanical properties of material. The following are effect of corrosion on mechanical properties.

Strength

Thickness reduction due to corrosion directly affects strength of materials. For example, 5” S-135 drill pipes premium class should have tensile strength of 436 klb; however, excessive corrosion damages internal and external surface area of drill pipes. The smaller surface area will result in reduction of tensile strength. Furthermore, it is very difficult to predict the strength of materials when localized corrosion occurs because a surface area of cracking don’t evenly distribute. Moreover, some of corrosive environments such as high temperature, high CO₂&H₂S, high chloride content, etc can dramatically degrade material properties.

Toughness

Corrosion reduces toughness of materials because it can physically and chemically change properties of materials and tough material can be brittle. Additionally, low temperature environment can dramatically decrease toughness.  Therefore, equipment used in low temperature conditions as subsea pipeline, subsea BOP, riser, etc must be designed to be able to work in very low temperature environment.

Ductility

Corrosion can change ductile materials into brittle material and this causes failure of structure. Several situations leading to ductility reduction are low temperature, H₂S & CO₂ gas, cyclic load, etc.

References

Aadnøy, B. S., 2010. Modern well design. 2nd ed. London: CRC Press.

CALCE and the University of Maryland, 2001. Material Hardness. [Online]
Available at: http://www.calce.umd.edu/TSFA/Hardness_ad_.htm
[Accessed 26 November 2016].

Department of Engineering, University of Cambridge, 2002. Material selection and processing. [Online]
Available at: http://www-materials.eng.cam.ac.uk/mpsite/properties/non-IE/toughness.html
[Accessed 23 November 2016].

Javaherdashti, R., Nwaoha, C. & Tan, H., 2013. Corrosion and Materials in the Oil and Gas Industries. 1st ed. Boca Raton: CRC Press.

Papavinasam, S., 2013. Corrosion Control in the Oil and Gas Industry. 1st ed. Houston: Gulf Professional Publishing.

Vallourec Oil & Gas, 2015. Sour Service Carbon Steel Enhanced. [Online]
Available at: http://www.vallourec.com/OCTG/EN/products/material/sourserviceenhanced/Pages/default.aspx
[Accessed 25 November 2016]

In order to properly design a completion, reservoir rock and fluid properties must be carefully taken into account because they directly influence on equipment selection.  Reservoir properties (rock and fluid properties) which must be considered are as follows;

Rock Properties

Permeability (k)

Low permeability formation may require fracturing operation to enhance production. The completion for tight formations must be able to withstand pumping pressure and allow fracking fluid and proppant to flow through.

Formation Strength

Unconsolidated formations are required to complete a well with a sand control completion; thus, a well can be produced without any damage to downhole and surface equipment.

Formation Pressure

Reservoir pressure directly affects the pressure rating on all completions because all components must be able to work under reservoir condition. What’s more, formation pressure will affect how much flow of the well can produce.

Formation Temperature

High reservoir temperature will quickly degrade some components, especially elastomer, and this will result in well integrity issues due to pressure leakage. This is one of the critical concerns in selecting the right equipment to work under high temperature conditions.

Fluid Properties

 Type Reservoir Fluid

 Reservoir fluid directly affects the completion strategy. For gas reservoirs, there are some aspects for which oil reservoirs do not have the same level of concerns, such as velocity corrosion and rate dependent skin. Furthermore, Water Gas Ratio (WGR) is another critical part of tubing size selection because water has much higher density than gas and it will reduce the vertical lift performance (VLP) of the well.  However, most of artificial lift methods as gas lift or down hole pumps cannot be used in gas wells.

For oil reservoirs, two key parameters, water cut and gas oil ratio, must be carefully accounted for when selecting the proper size of completion tubing. Another important part is an artificial lift planned to use in a well. Oil production can be enhanced by several artificial lift methods for instant down hole pumps, a beam pump, gas lift, etc. Hence, the artificial lift tool will affect size the completion string and production tubing.

PVT of Reservoir Fluid

A phase envelope of reservoir fluid analyzed from PVT data is imperative to completion selection because it informs about the condition of reservoir fluid at a down hole and a surface condition. For example, fluid at a reservoir condition is liquid, but when it flows to surface, it may become both liquid and gas. The mixture of the produced fluid influences the completion size selection, completion strategy and available recovery enhancement methods.

 H₂S Content

H₂S content will accelerate corrosion of all components and potentially harm human life. Consequently, for reservoirs with a high level of H₂S, all completion components both metal and non-metal must be sour service material. Example of sour service grade metal is VM SS grade (Vallourec Oil & Gas, 2015). Internal plastic coating is also a good method to prevent H₂S corrosion. Furthermore, a completion string must be designed to facilitate corrosion a inhibitor injection.

 CO₂ Content

 CO₂ reacting with water causes acid which will increase the corrosion rate on steel components. Special steel for instant Nickel-and Cobalt-Based Alloys, 13%Cr steel or Duplex Stainless Steel must be utilized to ensure well integrity. Elastomer in CO2 service is recommended to use nitrile sealing materials (Stone, et al., 1989). Additionally, completion must provide access to inject any corrosion inhibitor.

References

Aadnøy, B. S., 2010. Modern well design. 2nd ed. London: CRC Press.

Fjelde, K. K., 2013. E-learning modules – Drilling. [Online]
Available at: http://folk.uio.no/hanakrem/svalex/Misc/Drilling_&_Geology_2012_ResourcePres_Festningen_Long.pdf
[Accessed 19 November 2016]

Baker, R. (2001) A primer of oilwell drilling: A basic text of oil and gas drilling. 6th edn. Austin, TX: Petroleum Extension Service, Continuing & Extended Education, University of Texas at Austin.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Casing while drilling (CwD) has been around for many years and it is one of proven technologies that can save both time and money. CwD is a process where a well is simultaneously drilled and cased; the casing is used for the drill string, and is rotated to the drill and cemented into the well at TD. One of the main benefits of this process is that it greatly cuts down on the tripping time needed to pull out the bottom hole assembly (BHA) and run the case- if not removing this need entirely. Therefore, the flat time is reduced, and the process is made more economically viable.

Figure 1- Casing while Drilling Operation (Courtesy of Weatherford)

As shown in Figure 2 below, which is an example of Casing while Drilling utilized in one of oilfields in Oman for drilling surface section; this process can save up to 37.5% of time spent on a well based on historical data.

Figure 2 – A comparison between conventional drilling and casing while drilling of one field in Oman (SPE 136107-PA ,SPE Journal Paper – 2012).

Types of Casing while Drilling Systems

Three main types of CwD, which is determined by the configuration and operation of the drill, are as follows;

• Non-Retrievable Casing While Drilling System
• Retrievable BHA Casing While Drilling System
• Drilling with Liner Systems

Non-Retrievable Casing While Drilling System

The non-retrievable system is the simplest type of CwD. In this case, the system is made up of a drillable bit or drill shoe, a casing string, and a casing drive system. The drill shoe is fitted securely to the bottom of the casing string; the latter is rotated by a power swivel which is hooked up to the drive system. This system only offers a limited number of options- it can only drill in a straight hole, and to a pre-determined depth.

Figure 3 – Non-Retrievable Casing While Drilling System

Multiple drill shoes are available, which vary according to hardness and strength. Figure 4 is an example of a drill shoe manufactured by Weatherford.

Figure 4 – Weatherford Drill Shoe (Courtesy of Weatherford)

In order to provide proper rotational movement, and to pump through casing, water brushing is normally used in the drilling process. However, this is not a viable option when drilling using CwD, since the make up and breakout of water brushing means that the drilling threads are more likely to become damaged. The casing drive system used for CwD is specifically built based on the casing spear principle integrated with a cup-type packer seal. This then internally slots into the new joint of the casing. It is then able to connect to, pump, and rotate the casing properly. Once the casing joint is drilled down, the casing drive system rapidly disengages by releasing the casing spear. However, this spear requires a large gripping surface to properly distribute the load and prevent pipe deformation. The internal catch is suitable for large casing up to 13-3/8”, whereas an external catch is necessary for casing which is smaller than this.

Retrievable BHA Casing While Drilling System

The retrievable casing while drilling BHA system strikes a balance between conventional drilling tools and CwD. The main advantage of this system is that it can be steered, and used with both conventional measured while drilling (MWD) and logging while drilling (LWD) tools.

Figure 5 – Retrievable BHA Casing While Drilling System

Most BHA systems are connected to the bottom of the casing string, and drill a pilot hole. This hole can then be enlarged using one of three methods: 1) a reaming casing shoe, 2) a near casing shoe underreamer, or 3) a near bit underreamer.

Advantages and disadvantages of all three hole enlargement methods are shown below;

Reaming Casing Shoe

Advantages

• Maintain good directional control and LWD reading
• No risk of reamer not collapse when retrieving

Disadvantages

• Rat hole equal to BHA length. This will leave the longest rat hole among three methods.
• Limited reamer RPM equals to casing RPM

Near Casing Shoe Underreamer

Advantages

• Shorter rat hole
• Enable to improve reamer performance with PDM

Disadvantages

• Risk of underreamer stuck

Near Bit Underreamer

Advantages

• Shortest rat hole
• Enable to improve reamer performance with PDM

Disadvantages

• Risk of underreamer stuck
• Effect on LWD reading and directional control performance

The pilot BHA connects with the main casing, using Drill-Lock-Assembly (DLA) to set in the casing profile nipple (CPN). Once it has reached the TD, the BHA can then be retrieved using a drill pipe or a wireline; which method is used will depend on the weight and angle of the BHA.

Figure 6 – Drill-Lock-Assembly

The BHA system can cause a rathole of the same length as the BHA itself; for that reason, there are two techniques used to minimize the rat hole. Firstly, the DLA may be released at the TD, and reamed down with a casing reamer shoe up to the full bit length- this method can damage the BHA, though. An alternative to this method is to place the underreamer behind the bit; when the BHA reaches the TD, the DLA is then released, and the casing is able to be run all the way to the bottom. However, by positioning the underreamer behind the bit effects when using an LWD reading can impact upon directional control performance, particularly when using a rotary steering system (RSS). RSS is a popular choice when using CwD, given that it performs better than mud motors or positive displacement motors (PDMs). Drilling with mud motor is particularly difficult to use in conjunction with CwD, because it requires a larger contact area with the wellbore in order to effectively control the tool face.

With this system, cementing is usually done after BHA retrieval. Using a pump down float, which is dropped into the casing and pumped to lock in at the CPN, the cementing can be quickly and easily performed normally.

Drilling with Liner Systems

Drilling with Liner (DwL) works in much the same way as the previous two systems, except it does not involve the use of a casing drive system. The liner hanger setting tool is connected to the drill pipe, and then attaches to the power swivel at surface. There are three sub-types of this system: non-retrievable, wireline retrievable and drill pipe retrievable.

Figure 7 – Drilling with Liner Systems

Once the drill has reached the TD, the non-retrievable DWL is able to set the liner hanger, and then complete the cementing job. With a retrievable DWL, the BHA needs to be retrieved once the liner hanger has been set, before a liner wiper plug latching system or cement retainers are run with the liner top packer and seal assembly to set in the polished bore receptacle (PBR) atop of liner. When the seal assembly is attached to the liner, the cementing can then be carried out normally.

The advantages and disadvantages of each system are listed below

Non retrievable Drilling with Liner (DwL)

Advantages 

• Minimal rat hole
• No downhole tools to retrieve
• No rig modifications
• Not as expensive as others
• Quick cementing upon reaching section TD
• Relatively simple operations

Disadvantages 

• Limitations in drilling shoe size used
• No directional and MWD capabilities
• Only cased hole logs can be acquired
• Possible lack of availability of technology
• Torque limitations

Wireline retrievable Drilling with Liner (DwL)

Advantages 

• Directional and LWD capabilities
• Higher torque applications than non-retrievable DWL
• No rig modifications

Disadvantages

• Higher operating cost
• Multiple trips are required to retrieve BHA
• Possible lack of availability of technology
• Rathole length equals to BHA length
• Risk of BHA being irretrievable
• Unable to cement immediately upon reaching TD

Drillpipe retrievable Drilling with Liner (DwL)

Advantages 

• Directional and LWD capabilities
• Downhole tools can be retrieved in one trip after setting liner
• Highest torque applications
• No rig modifications
• Stable drilling system with low vibrations

Disadvantages 

• Higher operating cost
• Possible lack of availability of technology
• Rathole length equals to BHA length
• Risk of BHA being irretrievable
• Unable to cement immediately upon reaching TD

References

Australian Drilling Industry Training Co (ed.) (2013) The drilling manual: The manual of methods, applications, and management. 2nd edn. Boca Raton, FL: CRC Press.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Cantu, C. (2012) Technology adoption: No risk means no gain. Available at: http://www.drillingcontractor.org/technology-adoption-no-risk-means-no-gain-13073 (Accessed: 11 December 2016).

Schlumberger Limited . (2016) TDDirect Casing-Drilling and liner-drilling technology. Available at: http://www.slb.com/services/drilling/drilling_services_systems/casing_drilling.aspx (Accessed: 11 December 2016).

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

PennWell Corporation (2012) Casing drilling marks a century of progress. Available at: http://www.offshore-mag.com/articles/print/volume-72/issue-10/drilling-and-completion/casing-drilling-marks-a-century-of-progress.html (Accessed: 11 December 2016).

Sánchez, F. J., Said, H., Turki, M., & Cruz, M. (2012, June 1). Casing While Drilling (CwD): A New Approach To Drilling Fiqa Formation in he Sultanate of Oman–A Success Story. Society of Petroleum Engineers. doi:10.2118/136107-PA

Tesco Ltd (2014) Tesco Drill-Lock-Assembly. Available at: http://www.drillingcontractor.org/dcpi/2004/dc-julaug04/July4-Tesco.pdf (Accessed: 11 December 2016).

Weatherford Ltd (2013) Drilling with Casing services. Available at: http://www.weatherford.com/en/products-services/well-construction/tubular-running-services/total-depth-services/drilling-with-casing-services (Accessed: 11 December 2016).

Casing while drilling provides immediate benefits, saving both time and money by altering the steps needed for the drilling process. On top of this, the CwD system also provides a whole host of additional benefits. The benefits of casing while drilling can be summarized below;

Save Time and Cost

As mentioned in the introduction part, Basic Knowledge of Casing while Drilling (CwD), CwD is able to save operation time by cutting down flat time and reducing operational risk. When compared to conventional drilling, CwD can provide a time saving of between up to 37.5% of time spent on a well based on historical data from a field in Oman (136107-PA SPE Journal Paper – 2012).

Figure 1 – A comparison between conventional drilling and casing while drilling of one field in Oman (136107-PA SPE Journal Paper – 2012).

Get Casing to Total Depth

Because of wellbore degradation, conventional drilling is usually unable to run casing all the way to the bottom of a hole. This degradation is caused by a number of factors, including wall damage, filter cake build up, and open hole time left for long time. However, a non-retrievable system allows casing string to drill all the way through ledges and other obstacles, fit through tight sections, and reach the TD successfully.

Reduce Formation Exposure Time

Introducing the casing during the drilling process also removes tripping times for BHA. This doesn’t just save on costs, but it also helps to reduce the formation exposure time that is usually an issue until cementing. This exposure time can cause mud degradation, salt creeping, and clay swelling, but these problems are eliminated by CwD. What’s more, since there is no need for an additional casing run after the initial drilling, there is less risk of the casing getting stuck.

Overcome Challenging Drilling Zones

CwD can also be used to deal with potentially challenging drilling zones, such as depleted formations, salt sections, and fractured zones. This is because CwD allows one to set and case off a zone instantly once it has been drilled. Conventional drilling, on the other hand, takes longer to deal with these areas, and can even complicate the problem, meaning a significant amount of both time and money is spent trying to recover the well, not taking into account the severe formation damage which can also be caused.

Improve Hole Cleaning

When CwD is used, it creates a small, uniform annulus between the casing and the borehore. This is beneficial because it means the drill is able to circulate and clear cuttings easily, without the need for a high slow rate. It is important to note, though, that drilling fluid properties and pipe movement need to be planned out carefully in advance to ensure that the hole remains clean.

Improve Hole Quality

By using casing while drilling, one can see that the hole quality is significantly higher than with conventional drilling. This is due to a process known as the plastering effect (Figure 2), in which cuttings and filter cake are crushed up and pressed into the formation by the rotation of the smooth pipe. This creates a low permeability wall cake. On the other hand, pipe rotation is not smooth in conventional drilling processes; a wall cake is produced, but it easily comes off the formation, and is therefore less effective.

Figure 2 – Wellbore stability improvement by Casing while Drilling (right) compared to conventional drilling (left) Courtesy of Schlumberger

Reduce Mud Loss

Thanks to the mud cake produced by cementing, drilling fluid is kept within the formation, thus sealing off the wellbore and preventing circulation problems. CwD therefore makes it possible to continue drilling in a more controllable fashion. CwD requires a lower flaw rate than a conventional drilling at the same annular velocity because the clearance between wellbore and casing is much smaller than wellbore and drill pipe. Therefore, hole cleaning can be improved. Conventional drilling requires that the drill be stopped to solve lost circulation problems, and often needs the setting of cement plugs, which can cause a great deal of hours non-productive time (NPT) which can soon add up to a great expense.

Wellbore Strengthening

Not only does this help to limit mud loss, but it also improves upon formation fracture resistance, a process known as wellbore strengthening. The cuttings and filter cake are crushed into the formation, sealing up tiny cracks and giving some additional integrity to the area around the wellbore, while also giving a wider mud weight window.

Improve Formation damage

Casing while drilling has a plastering effect, which is beneficial because it creates a mud cake layer that is impermeable, preventing the productive zone from being blocked up by both liquid and solid materials. Damaged zones are much smaller with CwD than conventional drilling, which is demonstrated in Figure 13. This means that the well is more productive, and damage is kept to a minimum. However, this point is still being contested by some, as the results of research may be seen to be inconclusive.

Reduce Operational Problems

Some operational issues such as stuck pipe and well control can be minimized by Casing while Drilling. The reasons are explained below;

• Stuck Pipe

A stuck pipe mechanism can be diagnosed into three major categories: differential, mechanical and solid induced stuck. In theory, a larger casing area should be more likely to suffer from a differential stick, but in practice, it is actually less likely. This is due to the effects of plastering, which creates a fine, impermeable layer that acts as a barrier, and keeps differential pressure to a minimum.

Mechanical sticking usually comes about due to micro-dogleg, undergauge holes, or mobile formation. CwD eliminates the first two causes by starting and ending the drill process with the casing. In terms of mobile formation, CwD reduces exposure times to limit the risk of this happening.

As CwD results in superior hole cleaning, the pack-off which is caused by cutting accumulation is drastically lowered. In addition, the plastering effect provides additional structural support. This means that CwD helps to eliminate the problem of stuck pipes, and is therefore useful for wells with a stuck pipe problem.

• Well Control

Conventional drilling often causes well control situations which need to be dealt with accordingly. This is due to tripping; therefore, since CwD eliminates tripping BHA, this risk is reduced. With retrievable BHA systems, the large by-pass between the BHA and the casing eliminates swabbing, and keeps the casing string firmly on the bottom, further reducing the risk of well control.

References

Australian Drilling Industry Training Co (ed.) (2013) The drilling manual: The manual of methods, applications, and management. 2nd edn. Boca Raton, FL: CRC Press.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Cantu, C. (2012) Technology adoption: No risk means no gain. Available at: http://www.drillingcontractor.org/technology-adoption-no-risk-means-no-gain-13073 (Accessed: 11 December 2016).

Karimi, M., Moellendick, T. E., & Holt, C. (2011, January 1). Plastering Effect of Casing Drilling; a Qualitative Analysis of Pipe Size Contribution. Society of Petroleum Engineers. doi:10.2118/147102-MS

Schlumberger Limited . (2016) TDDirect Casing-Drilling and liner-drilling technology. Available at: http://www.slb.com/services/drilling/drilling_services_systems/casing_drilling.aspx (Accessed: 11 December 2016).

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

PennWell Corporation (2012) Casing drilling marks a century of progress. Available at: http://www.offshore-mag.com/articles/print/volume-72/issue-10/drilling-and-completion/casing-drilling-marks-a-century-of-progress.html (Accessed: 11 December 2016).

Sánchez, F. J., Said, H., Turki, M., & Cruz, M. (2012, June 1). Casing While Drilling (CwD): A New Approach To Drilling Fiqa Formation in he Sultanate of Oman–A Success Story. Society of Petroleum Engineers. doi:10.2118/136107-PA

Tesco Ltd (2014) Tesco Drill-Lock-Assembly. Available at: http://www.drillingcontractor.org/dcpi/2004/dc-julaug04/July4-Tesco.pdf (Accessed: 11 December 2016).

Weatherford Ltd (2013) Drilling with Casing services. Available at: http://www.weatherford.com/en/products-services/well-construction/tubular-running-services/total-depth-services/drilling-with-casing-services (Accessed: 11 December 2016).

Offshore structures (rig and production platform) are complex facilities to drill wells (options) and produce gas from wells from offshore locations. This is one of the most fascinating structures in the world and this article will show 5 largest offshore structures on the planet.

1. Berkut Platform

Berkut Platform (Courtesy of Rosneft)

Berkut is the world’s biggest oil platform which has begun commercial production at the Sakhalin-1 offshore project in Russia’s Far East. The Berkut oil rig is expected to extract 4.5 million tons of oil annually. The Sakhalin-1 Consortium was formed in 1996 is the first major shelf project in Russia created under terms of a Product Sharing Agreement (PSA). The international consortium is made up of the US major ExxonMobil (30 percent), Japan’s Sodeco (30 percent), Russia’s Rosneft (20 percent) and India’s ONGC Videsh (20 percent). The Berkut platform is expected to produce 12,000 tons of oil daily or about 4.5 million tons annually, raising the total output of the Sakhalin-1 Consortium to 27,000 tons a day.

2. Perdido Platform

Perdido Platform (Courtesy of Shell)

Perdido is the deepest floating oil platform in the world at a water depth of about 2450 meters (8000 feet) operated by the Shell Oil Company in the Gulf of Mexico. The Perdido is located in the Perdido fold belt which is a rich discovery of crude oil and natural gas that lies in water that is nearly 8000 feet deep. The platform’s peak production will be 100,000 barrels of oil equivalent per day. At 267 meters, the Perdido is nearly as tall as the Eiffel Tower.

3. Petronius Platform

Petronius Platform

Petronius is a deepwater compliant tower oil platform operated by Chevron Corporation and Marathon Oil in the Gulf of Mexico, 210 km southeast of New Orleans, United States.

A compliant piled tower design, it is 609.9 metres (2,001 ft) high, and was arguably the tallest free-standing structure in the world, until surpassed by the Burj Khalifa in 2010, although this claim is disputed since only 75 metres of the platform are above water. The multi-deck topsides are 64 metres by 43 metres by 18.3 metres high and hold 21 well slots, and the entire structure weighs around 43,000 tons. Around 8,000 m3 (50,000 barrels) of oil and 2,000,000 m3 (70 million cubic feet) of natural gas are extracted daily by the platform.

The platform is situated to exploit the Petronius field, discovered in 1995 in Viosca Knoll (block VK 786) and named after Petronius, the Roman writer. The seabedis 535 m (1,754 ft) below the platform. The compliant tower design is more flexible than conventional land structures to cope better with sea forces. It can deflect (sway) in excess of 2% of height. Most buildings are kept to within 0.5% of height in order to have occupants not feel uneasy during periods of movement.

4. Hibernia Platform

Hibernia Platform (Courtesy of Exxon Mobil)

The production platform Hibernia is the world’s largest oil platform (by weight) and consists of a 37,000 t (41,000 short tons) integrated topsides facility mounted on a 600,000 t (660,000 short tons) gravity base structure. The platform was towed to its final site, and 450,000 t (500,000 short tons) of solid ballast were added to secure it in place. Inside the gravity base structure are storage tanks for 1.2 million barrels (190,000 m3) of crude oil.

Facts about Hibernia

• Hibernia was the world’s first iceberg-resistant gravity-based structure and remains Canada’s largest offshore platform.
• The Hibernia platform is able to withstand contact with a six-million ton iceberg.
• Our robust iceberg management system uses satellite, aerial and marine reconnaissance to detect icebergs and safely alter their trajectory away from the platform.
• ExxonMobil’s advanced oil recovery technology has been used to support both water and gas injection at Hibernia, with the potential to recover as much as 60 percent of the hydrocarbon resource.

5. Mar B/Olympus Platform 

Olympus Platform (Courtesy of Shell)

Olympus (Mars B development) is owned by Shell and is the company’s largest floating deep-water platform. The hull was built in South Korea, and became operational in February 2014.

First oil production begun in January 2014 from the Mars B development through Olympus, Shell’s seventh, and largest, floating deep-water platform in the Gulf of Mexico.

Combined production from Olympus and Shell’s original Mars platform is expected to deliver an estimated resource base of 1 billion barrels of oil equivalent (boe). Olympus is a tension leg platform (TLP) featuring 24 well slots, a self-containing drilling rig, and capability for subsea tie-backs.

In addition to the Olympus drilling and production platform, the Shell Mars B development includes subsea wells at the West Boreas and South Deimos fields, export pipelines, and a shallow-water platform, located at West Delta 143, near the Louisiana coast.

Olympus sits in approximately 3,100 feet of water (945 metres). Using the Olympus platform drilling rig and an additional floating drill rig, development drilling will enable ramp up to an estimated peak of 100,000 boe per day in 2016. The Mars field produced an average of over 60,000 boe per day in 2013.

References

“TV-Novosti”AutonomousNonprofitOrganization (2016) Biggest oil rig ever: 200k-ton Sakhalin giant begins production. Available at: https://www.rt.com/news/224371-oil-rig-berkut-extraction/ (Accessed: 14 December 2016).

ROSNEFT (2016) Rosheft and ExxonMobil have installed unique Berkut platform on Sakhalin shelf. Available at: https://www.rosneft.com/press/news/item/153343/ (Accessed: 14 December 2016).

Shell Global (2016) ‘Perdido (oil platform)’, in Wikipedia. Available at: https://en.wikipedia.org/wiki/Perdido_(oil_platform) (Accessed: 14 December 2016).

Shell (2010) Perdido. Available at: http://www.shell.com/about-us/major-projects/perdido.html (Accessed: 14 December 2016).

Wikipedia (2016) ‘Petronius (oil platform)’, in Wikipedia. Available at: https://en.wikipedia.org/wiki/Petronius_(oil_platform) (Accessed: 14 December 2016).

OffshoreTechnology.com (2012) Petronius. Available at: http://www.offshore-technology.com/projects/petronius/ (Accessed: 14 December 2016).

Wikipedia (2016a) ‘Hibernia oil field’, in Wikipedia. Available at: https://en.wikipedia.org/wiki/Hibernia_oil_field (Accessed: 14 December 2016).

Exxon Mobil Corporation (2003) Learn more about ExxonMobil’s presence in the arctic. Available at: http://corporate.exxonmobil.com/en/current-issues/arctic/presence/our-arctic-presence (Accessed: 14 December 2016).

Shell Corporation (2016) Mars B/Olympus deep-water project. Available at: http://www.shell.us/energy-and-innovation/energy-from-deepwater/shell-deep-water-portfolio-in-the-gulf-of-mexico/mars-b-olympus.html (Accessed: 14 December 2016).

Water phase salinity is a factor showing the activity level of salt in oil based mud. In order to control the water phase salinity, salt is added into the drilling fluid. The salt added into the system will be dissolved by water in the mud; therefore, the chloride content will increase.

By increasing the chloride concentration (adding salt), the activity level in the mud will decrease. Salt is added in order to create an activity level which is equal to or less than formation water. Therefore, the water phase in the mud will not move into formation and cause a clay swelling issue. Practically, calcium chloride (CaCl2) or sodium chloride (NaCl) is the chemical to be used.

When salt must be added into the mud system?

Typically, while drilling with oil based mud, cuttings are generally dry, hard, and easy to break into pieces. However, if the cuttings come together in big pieces and are wet, it may increase salt content in the drilling fluid. The reason is that water in the mud moves into formations and swells the clay particles in the formation. Swelled clay causes wet and mushy cuttings.

References

Andy Philips, 2012. So You Want to be a Mud Engineer: An Introduction to Drilling Fluids Technology. Edition. CreateSpace Independent Publishing Platform.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Ryen Caenn, 2011. Composition and Properties of Drilling and Completion Fluids, Sixth Edition. 6 Edition. Gulf Professional Publishing.

The technology used for offshore oil and gas production has always needed to be flexible and fast-developing, in order to meet the wide range of challenges that different environments can present. Overall, the most important requirement of this technology has been a working deck which is mounted on a larger structure that provides enough space for all necessary production equipment, like processing facilities to separate oil, gas, and water, as well as pumps, compressors, connections, and living space for workers on the rig.

When platform development was not so advanced, the well drilling would usually be completed before the production process began, to ensure the safety of workers. Additional equipment and accommodation would also usually be located on a separate structure for the same reason. However, as wells were constructed in ever deeper water, new types of platforms needed to be designed.

Deep-water structures are very high-cost, and it is therefore more economically viable to accommodate workers and equipment on a single platform. Coupled with improved safety practices and fire prevention, this means that is now commonplace for offshore development to be situated on just one structure.

The most fundamental requirement for offshore drilling is a platform from which the whole operation can be run. In most cases, this is done from a fixed platform, but in recent decades floating production facilities have been successfully developed, and these are becoming increasingly common. These floating production units are the most commonly used when it comes to deep-sea applications.

With fixed platforms, there are two basic types, both with a subset of variations for specific purposes. These two types are piled structures and concrete gravity structures (Figure 1). Neither has gained precedence over the other, mainly because of frequent changes in the cost of materials, equipment, and specialized labor needed to construct them, as well as changing demands from the offshore industry as to the size of the platform.

Figure 1 – Piled Structure and Gravity Structure of Brent (Courtesy of Shell UK)

Each type has its own disadvantaged. Piled structures can be lengthy and costly to build, and during this period they are susceptible to damage from bad weather. They also lack oil storage capacity, and drilling and processing facilities and living space must be constructed only when the base structure has been fully completed. On the other hand, concrete gravity structures are more expensive to put together, and once the foundation has been put down, they are difficult to modify, meaning if the soil conditions change even slightly from those anticipated, there could be problems with the structure that are highly expensive to put right. In this article, it will describe basic details of piled offshore structure.

Piled Offshore Structures

Initial offshore structures were designed fairly simply, using large (24 in and 30 in) diameter tubular steel piles driven into the seabed using steam hammers. These structures were primarily used in areas with a soft, muddy seabed, such as the Gulf of Mexico, Lake Maracaibo, the Gulf of Paria between Trinidad and Venezuela, the South China sea offshore Brunei and Sarawak and the Arabian Gulf. Each platform needed either four, six, or eight piles, and once the pile driving operation was completed, the platform decks were then welded on top. Although the long piles would be penetrating thick layers of mud, they were still required to be driven straight and accurately. This need led to the development of the so-called “jacket” technique of pile-driving.

In this method, a frame is created onshore which is high enough for continuous conductor pipes to be attached. These pipes are then used to drive piles from above the surface into the seabed, while the jacket rests on the bed with little bearing pressures to ensure the jacket is stable and vertical throughout the pile driving process. The jacket is taken to the offshore site on a barge, before being launched into the sea. While it will initially float horizontally, by gradually ballasting specific leg members, it can be brought into an upright position, before additional ballasting is used to fix it into the seabed. Early structures only used the jacket as a pile driving construction tool, and not as a part of the structure itself.

Figure 2 – A Traditional Large Steel Jacket Platform

As water depths increased, and top loads became more heavier and heavier, the jacket needed to not only be used for construction, but also be fitted to the structure itself. This meant that engineers had to come up with a way to drive multiple piles from around the base of each jacket leg. In the picture above, up to eight piles are driven in a cluster around each jacket leg, with sufficient clearance between piles. Clusters of piles act as a group, rather than alone. It is now possible to create platforms of fifty-plus piles, and with diameters of up to 72 inches.

Figure 3 shows the pile guide of a modern jacket for an offshore platform. Steel piping is driven through these holes before being cemented into place, so as to keep the fixed structure stable. When the platform is eventually removed, the pilings are cut through, allowing the platform to be towed away. However, this method of disposal results in a huge waste of steel. The piles can be cut using explosions, diamond wire cutting, or slurry jet cutting.

Figure 3 – Pile Guide of a Modern Jacket (Courtesy of Tamboritha)

Numerous variations on this original design have been created. Even in the years after its introduction, engineers were already trying out concrete piles as a substitute for the steel tubulars, although they proved to be insufficient due to their inflexibility in length. This meant that they were unusable when faced with an unexpected variation in length. Further developments included the use of higher tensile strength steels for both piles and jackets, which made significant savings in steel weight. As depths increased, the problems of fatigue and stress intensification in the joint frames has become a greater issue, and a large amount of research has gone into this area. The jacket design became so large that launch barges began to take up a significant portion of the construction budget, which led to the idea of self-floating jackets that eliminate the need for the launch barge. Several structures of this type have been used in the Gulf of Alaska, where the ability to resist impact force from large masses of drifting ice was a particular need.

The launch-type structure has remained the most popular, though, and nowadays jackets weighing over 20,000 tonnes have been prefabricated and placed successfully. These structures are able to support dead loads of up to 20,000 tonnes, roughly equivalent to a live load imposition of around 40,000 tonnes. Thanks to these enormous installations, water depths of over 125 meters have been successfully drilled, and steel platforms fitted to the seabed with piling have been constructed in water depths of over 250 meters.

Figure 4 demonstrates the typical launch sequence for a steel substructure fixed platform. The jacket is floated out to the intended location by barge, and then allowed to sink. Steel pilings are subsequently forced around 100 meters into the seabed inside the jacket. The platform itself can then be safely lifted onto the top of the sunken structure by crane, usually in multiple sections.

Figure 4 – The Launch Sequence of a Steel Substructure.

The Compliant Tower

Once oil and gas development started to move into deeper waters of over 1500 ft, steel platforms needed more materials, which led to a steep increase in price. Compliant towers were therefore used as a practical solution to this problem. These tall structures are built from cylindrical steel rods, and are slender in shape. They are piled into the seabed in the way as a standard steel platform. They differ in that the base covers a much smaller space, which means that the narrow base can way by as much as 15 ft in extreme weather conditions.

Compliant towers (CT) are designed so that their upper regions are buoyant and have a high mass. This means that they have a very slow response to any great force. Usually, a 10 to 15 second wave cycle passes through the frame before it can respond, akin to a water reed in a river. The Bullwinkle platform (Figure 5) below is a typical example of a CT on a large scale.

Examples of Piled Offshore Structures

The largest platform ever built is named the Bullwinkle, and is located in the Gulf of Mexico. It comes in at 412 meters high, and Figure 5 shows it was being floated out to its location. The Bullwinkle boasts a light lattice type construction, something not normally seen in platforms built for use in the North Sea. The Bullwinkle would not survive rough North Sea conditions because this structure is not strong enough.

Figure 5 -Bullwinkle oil platform shell (over 400m long)

Figure 6, on the other hand, shows three North Sea Valhall Field platforms which are joined together. Most platforms worldwide are nowhere near the size of the Bullwinkle, and are instead relatively small. Platforms in shallow water are small, which means limited deck capacity. This requires multiple platforms to be grouped together to make a full field. In Figure 6, the structure on the left is used for accommodation and as a helideck. The middle structure is used for drilling wells, and passes fluids from the wellhead to the facility on the rightmost structure, the process platform.

Figure 6 – North Sea Valhall Field Platforms

References

Ambiwlans (2014) Largest thing ever moved? Bullwinkle oil platform shell (over 400m long), think Sears tower. • /r/EngineeringPorn. Available at: https://www.reddit.com/r/EngineeringPorn/comments/2jjnlq/largest_thing_ever_moved_bullwinkle_oil_platform/ (Accessed: 22 January 2017).

Bai, Y. and Bai, Q. (eds.) (2012) Subsea engineering handbook. Waltham, MA: Gulf Professional Publishing.

Devereux, S. (2011) Drilling technology in nontechnical language. Tulsa, OK: PennWell Corp.

Energy-pedia. (2015) Norway: BP starts production from new Valhall platform in Norwegian north sea. Available at: http://www.energy-pedia.com/news/norway/new-153239 (Accessed: 22 January 2017).

Indian Maritime, Visakhapatnam and Indian Maritime University (2015) Sayan Bhattacharya. Available at: http://www.slideshare.net/ABHISHEKKUMAR790/introduction-to-offshore-structure-2 (Accessed: 22 January 2017).

PetroWiki (2013) Piled Offshore Structure. Available at: http://petrowiki.org/File%3AVol3_Page_537_Image_0001.png (Accessed: 22 January 2017).

Shell UK (2012) Brent Field Platonisms Available at: http://www.shell.co.uk/sustainability/decommissioning/brent-field-decommissioning/the-brent-story/_jcr_content/par/gallery/mediaplayer/image.img.800.jpeg/1480930096328/brent-field-cgi-highres.jpeg (Accessed: 22 January 2017).

As the name suggests, the concrete gravity structure is reliant on its own weight, and the capability of the seabed to maintain that weight, in order to remain stable. They are designed particularly with storm conditions in mind. Like other types of structure, they come in multiple design variations, and may be made out of concrete, steel, or a combination of the two. Concrete gravity structures were first used in the Ekofisk Field off Norway, although the design principle had previously been used in lighthouse construction. The Ekofisk structure, which had originally only been intended for oil storage but was then modified for use as a large gas handling and compression plant, was soon followed up with the construction of multiple additional drilling and production concrete gravity structures made from reinforced concrete. Given the huge demand placed on onshore prefabrication sites, and the significance of the water depths available to constructors for fabricating and towing these structures near to the shore, there has been a wide variety of different gravity designs, despite being constrained by the conditions of the construction site. It has been impossible to create an optimized design which is suitable to be built at all available sites.

The concrete gravity structure is built in a tapered shape, with as much of the mass and bulk concentrated as close as possible to the seabed. Ideally, the platform is constructed close to the shore, and the topside facilities are placed in a sheltered site before the offshore tow begins. Then, the whole thing is moved to its final location through the use of ocean-going tugs. This is done as much as possible using a multi-celled caisson raft, which can measure up to 100 meters high and 60 meters wide. From this raft base, a number of columns will be carried up to the full height of the structure. When the raft reaches the offshore location, the caisson is water ballasted and landed on the sea bed, Offshore installation can therefore take as little as a few days, which is certainly an advantage in harsh areas which have short fair weather periods. Concrete gravity structures can be used in water depths up to 160 meters and with weights of over 300,000 tonnes.

Examples of concrete gravity structures – Ninian Central Platform

Figure 1 demonstrates Ninian Central platform, a large concrete tower with a series of tanks around the base. These concrete fixed platforms are able to store fluids, and can also be attached to export lines, which gives them a significant advantage over steel jacket platforms. Jacket platforms generally lack tanks, although they can be built on deck, which means that their export can be entirely lost if a tanker does not stick to its strict schedule. Concrete platforms also do not need to be secured to the seabed. Thanks to skirts around the concrete, erosion is prevented. Concrete platforms perform exactly the same function as steel jacket platforms, with only the support structure being different.

Figure 1 – Ninian Central platform

Figure 2 shows the Ninian Central platform in bad weather, with only the top being visible. The accommodation block and satellite dishes can be seen on the left of the structure, as can several lifeboats. Since the Piper Alpha disaster, lifeboat stations are almost always located near the accommodation block. Ninian Central is a concrete monotower, weighing between 500 and 750 tonnes.

Figure 2 – Ninian Central platform on bad weather day

Condeep

Figure 3 demonstrates a large concrete fixed platform being built in a Norwegian fjord. This type of structure is known as a condeep. Tanks are built around the base of a concrete structure, which are used for sinking the platform when it is in its final position, and can then be used as storage tanks for produced reservoir fluids.

Figure 3 – Condeep

Modern Concrete Gravity Platforms

Figure 4 shows another significant advantage of concrete fixed platforms over steel jacket platforms. The main concrete structure can be built in the fjord, and then ballasted down to allow the mating of the main deck. This deck can then be built entirely onshore, before being sailed out to the concrete structure and attached. This is simply not possible with a steel structure. This picture shows a fairly typical modern platform. The accommodation block is the white structure on the far left, while the processing equipment is located on the opposite side for safety reasons.

Figure 4 – Modern Concrete Platform

Horsepower Requirement to Move a Platform

Figure 5 shows the vast amount of horsepower needed to move Troll A concrete platform with surface structure attached to its field location. The superstructure weighs around 25,000-30,000 tonnes, along with a jacket weight of 400,000 tonnes. Approximately 300,000 horsepower is therefore required to adequately tow and steer the structure.

Figure 5 – Troll-A Platform Under Tow.

Brent Field

Figure 6 shows the Brent field in the Central North Sea, one of the original Shell fields.  For the Brent field, one piled structure and three concrete gravity platforms were utilized for the field development. The platforms in this field are all close together, because technology limitations at the time meant each reservoir needed its own platform. Were Shell to build this field now, there would be no need for the four platforms. Thanks to modern subsea technology and extended reach drilling, the reservoir fluids could all be brought back to a single location for processing.

Figure 6 – Brent Field in Central North Sea (Courtesy of Shell)

References 

Bai, Y. and Bai, Q. (eds.) (2012) Subsea engineering handbook. Waltham, MA: Gulf Professional Publishing.

Bennett, M. (2015) Gearing up for the big lift in the north sea. Available at: http://www.bbc.com/news/uk-scotland-scotland-business-32844552 (Accessed: 25 January 2017).

Bygging-Uddemann (2015) Outstanding projects – bygging. Available at: http://www.bygging-uddemann.se/outstanding-projects/ (Accessed: 25 January 2017).

Devereux, S. (2011) Drilling technology in nontechnical language. Tulsa, OK: PennWell Corp.

Kaushik (2013) Troll-A platform: Largest object ever moved by man. Available at: http://www.amusingplanet.com/2013/03/troll-platform-largest-object-ever.html (Accessed: 25 January 2017).

Oilandgaspeople.com (2015) Production shut down on CNR north sea Ninian central – oil and gas news. Available at: https://www.oilandgaspeople.com/news/5842/production-shut-down-on-cnr-north-sea-ninian-central/ (Accessed: 25 January 2017).

Shell UK (2012) Brent Field Platonisms Available at: http://www.shell.co.uk/sustainability/decommissioning/brent-field-decommissioning/the-brent-story/_jcr_content/par/gallery/mediaplayer/image.img.800.jpeg/1480930096328/brent-field-cgi-highres.jpeg (Accessed: 22 January 2017).

Wikiwand. (no date) Slip forming. Available at: http://www.wikiwand.com/en/Slip_forming (Accessed: 25 January 2017).

We’ve discussed about two type of fixed platform structures which are piled offshore platforms and concrete gravity structures. In this article, it summarize the comparison between these two fixed offshore structures.

Figure 1 – Piled Structure and Gravity Structure of Brent (Courtesy of Shell UK)

Piled Platform Structures

Example of Pile Platforms – North Sea Valhall Field Platforms

• Horizontal stability is more reliable, allowing for a more economic design
• The final selection of the platform location is more flexible because the pile design is flexible to different soil conditions, and the pile can be modified even at a very late stage
• Material and fabrication costs are generally lower
• Site soil investigations can be less extensive, and costs therefore lower, so long as the decision to select a piled structure is made early on
• No need for a deep-water construction site
• Fabrication skills are mainly linked with steel working, meaning workers are easily available in shipbuilding areas
• Attaching pipeline risers to a steel structure is a simple procedure, and additional risers can be installed even after the structure is placed offshore
• When the site is abandoned, considerable work needs to be done to fully clear the area of debris, which adds cost at the end of the life of the platform.

Concrete Gravity Platform

Concrete Gravity Platforms

• Short installation times reduce cost, as well as exposure to weather risks
• Can potentially transport all deck and facilities to the offshore location after installation inshore, although this has rarely been carried out
• Capacity for oil storage on the platform
• Larger deck space can be provided
• Difficult to retrofit additional riser, as well as any other such alterations
• Construction is more reliant on unskilled labor, meaning workers will be more readily available for the project. However, construction sites need deep-water close to the shore, which will likely mean the construction site will be far from typical construction and industrial areas
• In theory, the structure can be de-ballasted and floated away at the end of its life, reducing the cost of abandonment, although this is yet to be put into practice.

References

mbiwlans (2014) Largest thing ever moved? Bullwinkle oil platform shell (over 400m long), think Sears tower. • /r/EngineeringPorn. Available at: https://www.reddit.com/r/EngineeringPorn/comments/2jjnlq/largest_thing_ever_moved_bullwinkle_oil_platform/ (Accessed: 22 January 2017).

Bai, Y. and Bai, Q. (eds.) (2012) Subsea engineering handbook. Waltham, MA: Gulf Professional Publishing.

Devereux, S. (2011) Drilling technology in nontechnical language. Tulsa, OK: PennWell Corp.

Energy-pedia. (2015) Norway: BP starts production from new Valhall platform in Norwegian north sea. Available at: http://www.energy-pedia.com/news/norway/new-153239 (Accessed: 22 January 2017).

Indian Maritime, Visakhapatnam and Indian Maritime University (2015) Sayan Bhattacharya. Available at: http://www.slideshare.net/ABHISHEKKUMAR790/introduction-to-offshore-structure-2 (Accessed: 22 January 2017).

PetroWiki (2013) Piled Offshore Structure. Available at: http://petrowiki.org/File%3AVol3_Page_537_Image_0001.png (Accessed: 22 January 2017).

Shell UK (2012) Brent Field Platonisms Available at: http://www.shell.co.uk/sustainability/decommissioning/brent-field-decommissioning/the-brent-story/_jcr_content/par/gallery/mediaplayer/image.img.800.jpeg/1480930096328/brent-field-cgi-highres.jpeg (Accessed: 22 January 2017).

Kaushik (2013) Troll-A platform: Largest object ever moved by man. Available at: http://www.amusingplanet.com/2013/03/troll-platform-largest-object-ever.html (Accessed: 25 January 2017).

There are many oil and gas discoveries which are out of reach of fixed structures for one reason or another. They may be in extremely deep water, or the oil or gas deposit might be too small or too widely spread to warrant the high cost of building a fixed structure. In these cases, seabed-completed wells may be connected to a floating platform moored above the field, using a production marine riser. The limiting conditions for fixed installations are not clearly defined, and they have been used in some cases for depths of over 250 meters, although this is in a benign environment. Floating platforms can also be used as the basis for an Early Production System (EPS), in which the appraisal wells drilled from a floating drilling vessel are completed at the seabed and produced to a floating platform carrying the required process plant and other facilities. This allows production to begin and create income whilst a fixed platform is being designed and installed for full field development. In this article, there are some discussions about three main types of floating offshore structures which are Tension Leg Platforms, SPAR and FPSO.

Tension Leg Platforms (Tethered Buoyant Structures)

One more form of offshore platform is what is known as the Tension Leg Platform, or Tethered Buoyant Structure. This method is intended for oil and gas production from water depths of over 500 meters. The platform works in much the same way as a taut moored buoy, which is anchored to the seabed using a vertical wire. The Tethered Buoyant Structure is basically a large, semi-submersible floating vessel, which uses a heavy gravity anchor to moor it to the seabed. Tension force is maintained in these vertical cables by adjusting the buoyancy of the floating platform, to ensure positive tension at all times. This method reduced marine response in the platform to effectively zero in vertical terms, and very little in horizontal terms. Horizontal drift can be further reduced as necessary. By using buoyance against a tension mooring system, this allows the use of a semi-submersible floating platform which can carry an additional load, balancing this out by increasing the buoyancy.

This type of structure is still under development, and there are still many problem points to iron out. How widespread it will become in the future is largely dependent on solving these issues, along with a thorough economic assessment comparing the system to other available ones.

Figure 1 – Tension Leg Platform

Example of Tension Leg Platform: Magnolia Platform (Figure 2) is an offshore oil drilling and production Extended Tension Leg Platform in the Gulf of Mexico. It is the world’s deepest ETLP, reaching 1,432 m, beating the Marco Polo TLP by 120 m. Wikipedia

Figure 2 – Magnolia Platform

SPAR

SPAR, which takes its name from the nautical term for booms and masts on a ship, is designed to present a small profile with minimal effect on wind and current. It uses an elongated cylindrical structure which floats in much the same way as an iceberg. This is moored to the seabed using steel or polyester cables. To keep a low center of gravity and prevent the SPAR from tipping over, the bottom of the SPAR features a ballast made of a heavy material, such as magnetite iron ore.  Due to the shape of its underwater profile, the SPAR is more vulnerable to vortex shedding (eddies), which can result in significant vibrations. To offset this, strakes are built into the frame.

Figure 3 – Spar Platforms (Courtesy of Technip)

Floating Production Storage & Offloading (FPSO)

A Floating Production, Storage and Offloading (FPSO) unit is a floating vessel used by the offshore oil and gas industry for the production and processing of hydrocarbons, and for the storage of oil. A FPSO vessel is designed to receive hydrocarbons produced by itself or from nearby platforms or subsea template, process them, and store oil until it can be offloaded onto a tanker or, less frequently, transported through a pipeline. FPSOs are preferred in frontier offshore regions as they are easy to install, and do not require a local pipeline infrastructure to export oil. FPSOs can be a conversion of an oil tanker or can be a vessel built specially for the application. A vessel used only to store oil (without processing it) is referred to as a Floating Storage and Offloading vessel (FSO).

Figure 4 – FPSO Credits: maersk.com

References

King, H. (2005) Magnolia TLP oil platform – the world’s tallest structure? Available at: http://geology.com/stories/13/magnolia-oil-platform/ (Accessed: 2 February 2017).

WikiPedia (2016) ‘Magnolia (oil platform)’, in Wikipedia. Available at: https://en.wikipedia.org/wiki/Magnolia_(oil_platform) (Accessed: 2 February 2017).

Wikipedia (2014) Floating production storage and offloading. Available at: https://en.wikipedia.org/wiki/Floating_production_storage_and_offloading (Accessed: 2 February 2017).

TechnipFMC (2014) Floating platforms. Available at: http://www.technip.com/en/our-business/offshore/floating-platforms (Accessed: 2 February 2017).

Even outside the drilling industry, the concept of directional drilling, whereby a drill is precisely guided through a particular target, is a fascinating one. This article will describe about applications of directional drilling in oil and gas industry. Later on, we will discuss in several aspects of directional drilling such as directional drilling tools, well path design, wellbore navigation tools, etc. Let’s get started.

Why Drill Directional Wells?

It is a fact that it is always more expensive to drill a deviated well to a target not directly below the rig location, as opposed to simply drilling down vertically to the target.

However, there is good reason why a directional well might be used: in some circumstances, it can actually lower the total cost of the project. Some potential reasons for this include:

Multiple exploration wells from a single wellbore

It is possible to drill a well to evaluate it, and then cement it back up. This well may then be deviated from its original path to an additional target. This may be done in order to evaluate multiple compartments in a single reservoir, if it is naturally split into several sections, or to extend the knowledge of the structure using a single well.

Figure 1 – Example of Multiple Exploration Wells from a Single Wellbore

Single surface location for multiple wells

The effective draining of reservoirs needs wells located across multiple parts of the reservoir. If possible, these wells should align towards a single surface location, so that all necessary production facilities may be located there. This is usually cheaper than connecting multiple wells from various surface locations. Production staff are centralized, which lowers running costs, and the rig only requires a single location. This is how drilling from an offshore platform works; a single platform could potentially connect to over 30 wells which spread out beneath it, which unite at the platform.

Figure 2 – Single surface location for multiple wells

Salt dome drilling

Some salt domes create additional structures that capture hydrocarbons. In these cases, it is often easier to drill around the salt dome instead of straight through it to reach a reservoir.

Figure 3 – Salt Dome Drilling

Onshore drilling to an offshore reservoir

It is more economically viable to reach an offshore target from onshore, rather than build an offshore platform. Wytch Farm (Figure 4), on the south coast of England, is one such example, and is in fact the largest onshore oil field in Western Europe, even though a great deal of it is located offshore. This area is environmentally sensitive, so operations were made economically possible by drilling from the land under the sea. Extended reach wells, which extend horizontally over twice their depth, allowed for this.

Figure 4 – Wytch Farm Oil Field (Southampton.ac.uk)

Side Track

It might be necessary sometimes to cement a well back to a shallower depth, and for a new wellbore to be drilled away from this original bore. This could be due to drilling problems, such as stuck pipe, or because an old producing well is to be sidetracked to a new location.

Figure 5 – Drill a Side Track Well

Optimum orientation in the reservoir

Unfortunately, reservoirs are not neat and tidy. Some directions will be more permeable than others. If a reservoir is in fractured limestone, then the well should aim to intercept as many of these fractures as possible to maximize production. Such factors determine the direction that the well should be drilled into the reservoir. Some wells may require very complicated well paths in order to achieve their prime position.

Relief wells

 In the worst possible scenario, a well is drilled as a relief well. This might be because, for instance, a well has suffered a blowout, and is blowing hydrocarbons into the surrounding environment, but the well cannot be killed from the surface. The relief well is then drilled to intercept the blowing well, and dense mud is forced into the blowing well to kill it from below. One example of this was the Deepwater Horizon disaster in the Gulf of Mexico in April 2010.

Figure 6 – Relief Wells (Macondo Well, Deep Water Horizon)

References

White, J. and Times-Picayune, T. (2010) Relief well work ahead of schedule, but timetable for halting gulf of Mexico oil spill stands. Available at: http://www.nola.com/news/gulf-oil-spill/index.ssf/2010/06/relief_well_work_ahead_of_sche.html (Accessed: 14 February 2017).

Inglis, T.A. (2010) Directional drilling. Dordrecht: Springer-Verlag New York.

Technical, T., Astier, B., Baron, G., Boe, J.-C., Peuvedic, J.L.P. and French Oil & Gas Industry Association (1990) Directional drilling and deviation control technology. Paris: Editions Technip.

Short, J.J.A. (1993) Introduction to directional and horizontal drilling. Tulsa, OK: PennWell Books.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

frackfreecv (2013) Why Wytch farm is a poor fracking comparison for Somerset. Available at: https://frackfreecv.wordpress.com/2013/12/16/why-wytch-farm-is-a-poor-fracking-comparison-for-somerset/ (Accessed: 15 February 2017).

The well planning process starts from geologists and reservoir engineers who decide the best place for the wellbore. They may only need to determine a single target, which will often be a tolerance of about 330 ft (100 m) around a certain target point. In this case, the angle at which the well enters the target can have various degree of deviation from the plan since a plan requires to hit only one target. On the other hand, it might be necessary for the well to penetrate multiple targets, with the final target being increasingly complex. This requires what is known as “geosteering”, a process which will be discussed later in the directional drilling series. The drilling engineer therefore needs to examine potential surface locations (if more than one is available) and design a well path which meets all necessary target requirements at the lowest possible cost. Cost can be minimized most effectively when there is a certain degree of flexibility when it comes to the surface location.

Directional Well Profiles

Well profiles can be simply divided into two groups which are 2-D design and 3-D design.

2-D Well Profile Design

The 2-D design well plan is a profile which inclinations are changed in order to hit required target but it does not have or slightly change in azimuth. The example of 2-D well profiles are shown in figure 1-4.

Figure 1 – J Profile (Build and Hold)

Figure 2 – S Profile (Build and Drop)

Figure 3 – Continuous Build

Figure 4 – J Profile + Continuous Build

3-D Well Profile Design

The 3-D well design have changes in both inclination and azimuth. The example of 3-D well profiles is illustrated in figure 5.

Figure 5 – 3D well profile (Gruenhagen, H et al., 2002)

Example of Well Planning

Figure 6 (Jones et al, 2008) provides an example of a planned well profile, from a plane view and a vertical view. This is a relatively simple directional well, which is designed to hit two targets, as shown by the boxes on the plan view. The easiest type of directional well profile is a so-called “J-shaped profile”, which is a build and hold to the target. The target in this case is an area, rather than a single point, and the well need not therefore hit the center of the target. Although it is possible to hit small targets, this increase in accuracy comes with a higher financial cost. In Figure 6, the lower target will be hit on the edge nearest to the surface location.

Figure 6 – J Profile Directional well plan (Jones et al., 2008)

This method has several advantages:

1. Opting for the nearest edge allows the well to be built to a lower inclination, and therefore not as much hole needs to be drilled.

2. Should the well fail to build angle at a fast enough speed, then it could end up missing its target. However, a higher build rate does not have a negative effect on the drilling ROP. On the other hand, reducing the angle to reach the target will mean compromising the drilling rate. This is caused by the fact that decreasing the angle usually required removing weight from the bit. However, this does not apply to all tools: some, such as rotary steerable tools, are exempt from this problem, although come at a higher financial cost. Unless the drilling operation already has a high daily cost, rotary steerable tools would not normally be used to correct a directional issue. If the low edge is aimed at, then directional correction work will not have a negative impact on drilling speed.

Other factors need to be taken into consideration when planning a well path. Whenever the well changes direction, the drillpipe needs to bend around that curve, and if the well is curved when still near the surface, this curve will cause additional drillpipe tension the deeper the well gets and the more weight is put on the drillpipe. This additional side force can cause numerous problems, including metal fatigue or wear on the pipe, and may even cause the pipe to become completely stuck.

Rate of Change in Direction

Rate of change in direction is measured in angle of directional change for every 100 ft (or 30 m) of hole drilled. This is known as the dogleg severity, as a dog’s leg bending is a signifier of a bent hole. High dogleg severity needs to be avoided while at a shallow point in the hole, since it causes high forces between the pipe and hole wall.

References

Gruenhagen, H., Hahne, U., & Alvord, G. (2002, January 1). Application of New Generation Rotary Steerable System for Reservoir Drilling in Remote Areas. Society of Petroleum Engineers.

Jones, S., & Sugiura, J. (2008, January 1). Concurrent Rotary-Steerable Directional Drilling and Hole Enlargement Applied Successfully: Case Studies in North Sea, Mediterranean Sea, and Nile Delta. Society of Petroleum Engineers.

Inglis, T.A. (2010) Directional drilling. Dordrecht: Springer-Verlag New York.

Technical, T., Astier, B., Baron, G., Boe, J.-C., Peuvedic, J.L.P. and French Oil & Gas Industry Association (1990) Directional drilling and deviation control technology. Paris: Editions Technip.

Short, J.J.A. (1993) Introduction to directional and horizontal drilling. Tulsa, OK: PennWell Books.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

VisCo (2011) Oil and gas – 3D animation – Shale drilling 02. Available at: https://www.youtube.com/watch?v=RZgAVjCw3OI (Accessed: 18 February 2017).

To deviate a well from a vertical path, and get it to follow an intended well trajectory , it is necessary to put some side force onto the bit. The amount of this, as well as its direction, are vital in order to keep the bit to its intended path. Other factors will also have an influence, including the hardness of the rock which is being drilled, as well as bedding plane angles. There are numerous different ways of developing a controlled side force on the bit. Two of the earliest developed methods are whipstock and jetting which will be discussed in this article.

Jetting as the Directional Drilling Tool

A tricone drill bit possesses three drilling cones, with a nozzle in between each one. Should a large nozzle be set into a single nozzle pocket, and two smaller nozzles used alongside it, then the majority of the mud flow would pass through the larger nozzle. Drilling fluid will be ejected from the drill bit with a significant amount of force, and so long as the formation is not overly hard, will erode the rock in its path. As the large nozzle directs the majority of the flow to a single point, a pocket will be carved into the rock in this direction. The well may be deviated simply by aligning the bit in the necessary direction, and then circulating without rotation.

Once between 5-6 feet have been washed away, the bit is then rotated, and drilling continues as normal. This process can be repeated continuously until an angle of around 12° is produced, or until rock is reached which is too solid to jet through. Figure 1 to 3 illustrate a jetting operation by a rotary drilling assembly, which is used to allow the well to keep building an angle while drilling and rotating take place.

Figure 1 – Jet a well to desired direction

Figure 2 – Drill a well into a jet direction

Figure 3 – Well deviated to the desired direction

Whipstock as the Directional Drilling Tool

After drilling the well to the kickoff point, the bit is pulled out of the hole. A whipstock is a wedge that is set in the hole. The fat edge of the wedge is on the bottom of the hole. The drillstring is rotated and the bit drills formation to the planned direction. Forced against the side of the hole, it starts to cut out of the original hole. After drilling below the whipstock, the bit is pulled out of the hole again. The drilling assembly is run back in. The deviation at the bottom of the hole will be worn and cut away as operations continue (Figure 4).

Figure 4 – Whipstock drill open hole (DrillEng-Group4-DirectionalDrilling-1)

Whipstocks are often used to sidetrack the well out of casing (Figure 5). Instead of a drill bit, a mill is used that can cut metal. In this application, the whipstock is left in place to guide tools through the cut in the casing. The drillstring will bend to allow the bottomhole assembly to go around the curved hole.

Figure 5 – Whistock for sidetrack the casing (Courtesey of Tadbir Petro energy)

Referrences

ایرانهاست (2017) Sidetracking Whipstocks – Tadbir Petro energy. Available at: http://tadbirpe.com/index.php/en/services/drilling/sidetracking-services/sidetracking-whipstocks (Accessed: 20 February 2017).

Directional Drilling Group (2015) Home. Available at: https://drilleng-group4-directionaldrilling-1.wikispaces.com/ (Accessed: 20 February 2017).

Inglis, T.A. (2010) Directional drilling. Dordrecht: Springer-Verlag New York.

Technical, T., Astier, B., Baron, G., Boe, J.-C., Peuvedic, J.L.P. and French Oil & Gas Industry Association (1990) Directional drilling and deviation control technology. Paris: Editions Technip.

Short, J.J.A. (1993) Introduction to directional and horizontal drilling. Tulsa, OK: PennWell Books.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

A positive displacement motor (PDM) is one of the most popular tool for drilling a directional well. It works by boring downwards and pumping mud through the motor itself. As shown in figure 1, the bottom section of the motor has an adjustable bend housing.

Figure 1 – Positive Displacement Motor (Courtesy of Schlumberger)

Before the motor is run into the hole, a set-up process needs to be carried out

1. The bend will be adjusted according to the directional performance that the motor needs to achieve. This bend is only very slight, usually being under 2°.

2. The motor is hooked up to navigational tools, which are then calibrated, in order for the driller to see where the bend is pointing when drilling. These tools are known as measurement while drilling, or MWD, and are described in detail later in this document.

3. The other parts of the system will be adjusted to account for the required directional performance- the severity of this will depend on the drill design.

In the illustration , figure 1, the main parts of the system are shown, moving from the bottom upwards:

• Drill bit – The motor is turned by mud which is pumped down the drillstring. The bit sits on a bent housing, and therefore does not point straight ahead. This causes a side force, which allows the bit to drill a curved hole.

• Near bit stabilizer – Smaller than the bit itself, this stabilizer forms a fulcrum, within which the motor acts as a lever, so that side force may be generated at the site of the bit.

• Mud motor – The bottom part of the motor itself has an adjustable bend. It converts hydraulic power from drilling fluid into mechanical power (rotating a bit)

• Dump valve – Above the motor, this valve can divert mud to the top of the motor if needed.

• Stabililzer – This piece acts as the end of the lever, and exerts an opposing force on the drill bit.

During the actual drilling process, the mud motor will be oriented in the desired direction so that the drill bit will be able to drill a directional well. This allows a change in inclination and azimuth, or a combination of the two. It is also possible to rotate the entire drillstring, to allow the bit to drill in a straight line at certain points. This explains why this system is also known as a steerable motor, since it can carve out a complicated path towards the desired target.

Mud motors are often used to begin the well from a vertical position, as well as to continue to control the well path at later points in the drill.  Once the well inclination exceeds 60°, it becomes increasingly difficult to make an “assembly slide” (a drill without rotating the drillstring) while in the process of drilling.

Mud motors also cause issues with keeping the hole clean. Rotation of the drillstring vastly improves the transport of cuttings out of the hole, but at high inclinations it can cause cutting beds to build up and stick to the drillstring, preventing it from working properly. A preferable approach would be to use a steerable tool which works while the drillstring rotates. While such a device does already exist, it is unfortunately a highly expensive tool.

The following videos will help you get more understanding about a mud motor and its configuration.

References

Inglis, T.A. (2010) Directional drilling. Dordrecht: Springer-Verlag New York.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

National Oilwell Varco (2017) National Oilwell Varco. Available at: https://www.nov.com/Segments/Wellbore_Technologies/Dynamic_Drilling_Solutions/InTerra_Sensors_and_Systems/Directional_Systems.aspx (Accessed: 26 February 2017).

Schlumberger Limited (2017) Schlumberger Drilling Services. Available at: http://www.slb.com/services/drilling.aspx (Accessed: 25 February 2017).

Short, J.J.A. (1993) Introduction to directional and horizontal drilling. Tulsa, OK: PennWell Books.

Technical, T., Astier, B., Baron, G., Boe, J.-C., Peuvedic, J.L.P. and French Oil & Gas Industry Association (1990) Directional drilling and deviation control technology. Paris: Editions