About Gefei Liu, PVI

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Casing Wear Series – 1: Causes

Posted on January 22, 2015 by Gefei Liu, PVI

During the drilling phase, the most costly component is the casing. On top of the expensive casing materials and the costs likely to be encountered in cutting, pulling and replacing a worn or damaged string, casing wear creates more serious problems for operators due to its potential catastrophic incidents such as oil spills, blow outs or loss of the well.

To analyze the forces behind casing wear, we need to study the torque and drag (T&D) of the drill pipe during drilling operations. The basic mathematical and physical model of T&D has not changed significantly since Johancsik et al. published their paper on T&D prediction. Pipe movements such as drilling ahead or tripping create drag, while rotation produces torque. The magnitude of T&D is determined by the combination of these two movements.

Since the so-called vertical well virtually does not exist (the whirring action of the bit always creates a micro-helical shape of the well path), the contact of the drill pipe and its tool joint with the casing ID is unavoidable. The gravitational force acting on the drill pipe is always trying to pull the pipe to the lower side of the wellbore, while the axial tension on the drill pipe (in a build-up section) tends to push the pipe to the upper side of the wellbore. Depending on the pipe weight, dogleg severity, and axial force along the pipe, the drill pipe either touches the upper or lower side of the wellbore.

Typical T&D analysis starts by dividing the pipe into small elements. Calculation begins from the bottom element of the pipe, where weight on bit (WOB) and torque on bit (TOB) are expected. For each element, force and torque are balanced and the T&D at the top of the element are calculated. From bottom to top, calculations are performed for each pipe element, until it reaches the rig floor. This step-by-step calculation also determines the direction and magnitude of the side force, which pushes the drill pipe against the wellbore as shown in Figure 1.

Figure 1. Snapshot of Side Force along a Drill Pipe

Under this side force, the rotating tool joint on the drill pipe against the casing inside, gradually removes steel from the casing wall and forms a crescent-shaped wear on the casing as shown in Figure 2.

Figure 2. Rotating Tool Joint Wears Crescent Grooves in Casing

The seriousness of friction between two contacting surfaces is dependent on the nature of the rubbing surfaces and the mud.

The tool joint coating plays a bigger role here compared to the casing wall. The industry has seen tool joint coating evolve from “casing killer” (rough tungsten carbide) to “casing friendly” as shown by many high-tech hardbanding materials.

Tungsten carbide is applied on the tool joint. While it is a very good protector of the tool joints, it aggressively wears the casing so much that the mud type and its additive will not help much in reducing casing wear if rough tungsten carbide is present.

Once a casing friendly tool joint coating has been selected, the mud type and its additives play an intermediate role in casing wear. Water-based mud causes twice as much casing wear as the oil-based alternative. Lubricant reduces friction and severity of the wear.

Generally speaking, high dogleg will create a high side force and severe casing wear. The wear profile resembles the shape of dogleg severity. Higher RPM and lower ROP make more rotation time between the tool joint and casing and will cause aggressive wear.

The following conditions contribute to casing wear:

Well path and dogleg
Drill pipe weight
Tool joint coating
Mud and additives
RPM and ROP

Casing Centralizer Series – 5: Are We Using Too Many or Too Few?

Posted on January 21, 2015 by Gefei Liu, PVI

Our industry is blessed with many talented and experienced engineers. We also have centralizer vendors producing the very best and top quality products. It is critical that we maximize the engineering potential while selecting the proper types of centralizers and placements. A software package like CentraDesign should be an integral part of the total approach of the centralizer placement optimization.

Theories and equations determining the casing deflection between centralizers are well established, even though a hand calculation for a deviated well is impractical.

Experience plus software technology enable both centralizer vendors and operators to conduct centralizer optimization prior to field execution.

Fig. 1. Total Approach of Centralizer Placement

When optimizing the centralizer placement, consider the following:

Each well is different. Our previous experience may not apply to the next well.
Operators aim to obtain a satisfactory standoff with less centralizers.
Similarly centralizer vendors aim to obtain a satisfactory standoff to sell more units.
Software like CentraDesign optimizes the centralizer placement and usage.
Computer modeling reduces risks and costs.

Centralizer placement can make or break a good cementing job. Computer modeling is not only an easy but also a necessary step to achieve optimization of centralizer usage. So, if you ask me the question: “Are we using too many or too few centralizers?” I would say: “If we all use readily available software to check the standoff profile for a specified spacing and optimize the placement, then we would probably use the correct number of centralizers.”

Casing Centralizer Series – 4: Case Study

Posted on January 19, 2015 by Gefei Liu, PVI

With the help of computer modeling, centralizer placement optimization becomes easy to perform for all types of wells. Ideally, this kind of optimization should be done before every casing job. Here is an example of centralizer placement optimization using the CentraDesign software.

Fig. 1. Example Well

The example well has a kick-off point at 2,000 ft. The previous casing (ID = 8.535”) was set at the same depth. Our goal is to centralize the 12,345 ft of 4 1/2” casing, deviated from 0^o to 90^o. The centralizer considered is the bow spring type with a restoring force of 800 lbf.

One approach to centralizer placement optimization is to specify the spacing using our experience and knowledge, and then let the software check if it yields a satisfactory standoff profile. We compare 2 cases: one with 40 ft (1 centralizer per joint) and the other with 20 ft (2 centralizers per joint) for the centralizer spacing. Fig. 2 shows the resulting standoff profiles. The blue line is the standoff at the centralizer, while the red line is the standoff at the middle point between centralizers, which is always lower than that of at centralizers. Since we are using the bow spring centralizers, the standoff at the middle point between centralizers is the summation of the casing sagging between centralizers and the bow spring compression at the centralizers.

Fig. 2. Standoff Profiles

For centralizer spacing of 40 ft, the number of centralizers required is 251. From 2,000ft to 7,000 ft (deviation from 0^o to 30^o), the standoff is between 100% and 70%, which meets the minimum industry standard of 67%. From 7,000ft to 12,345 ft (deviation from 30^o to 90^o), the standoff drops from 70% to 20%, which is problematic: poor standoff profile at this section may cause potential cementing problems.

The natural way to solve this problem is to try 2 centralizers per joint (spacing of 20 ft). The new standoff profile is much better than the normal industry standard, but with the doubled number of centralizers, this new approach may be too conservative, leaving engineers wondering: am I using too many centralizers?

Alternatively, we can specify the required standoff and let the software tell us how to space each centralizer. With the required 70% standoff throughout a 4 1/2” casing, CentraDesign displays the spacing necessary to achieve the specified standoff, as shown in the following figures. The total number of centralizers used is 200, a significant reduction from previous approaches.

Fig. 3. Calculated Spacing Required to Achieve 70% Standoff

Logically, as the well builds up from a 0^o to 90^o inclination angle, centralizer spacing decreases: casing needs more support in the deviated or horizontal sections. More advanced approach is to combine the “Specify spacing” and “Specify standoff” modes to yield the simple-to-install centralizer placement, yet satisfying standoff profile, by using incremental spacing options. Optimized centralizer placing not only produces good standoff, but also increases the efficiency of field installation of centralizers and avoids the excessive use of unnecessary centralizers.

Casing Centralizer Series – 3: Modeling

Posted on January 16, 2015 by Gefei Liu, PVI

We are going to study on the 5 parameters affecting casing standoff.

1. Well trajectory

Well trajectory is expressed in terms of survey data, consisting measured depth, inclination and azimuth angles. It defines the shape of the well path and thus has great impact on the direction and magnitude of the side forces that pull the casing string to the wellbore. Fig. 5 shows the magnitude and direction of the side force distribution on a casing in a horizontal well.

Fig. 1. Side Force Profile

For a casing section in a build-up or horizontal section of wellbore, the weight of pipe pulls the casing toward to the lower side of hole. The blue lines indicate that the casing touches the lower side of wellbore. The upper section of the casing string has to sustain the weight of lower casing sections. This creates tension force along the casing string. Wellbore doglegs cause the resultant force to pull the casing toward the upper side of the hole, as indicated by the red lines. Therefore, casing string in a deviated or horizontal well always touches the wellbore, upper or lower side.

Fig. 2. Side Forces with Casing Positions

Generally speaking, horizontal or extended reach wells require more support from centralizers to maintain a good standoff profile.

2. Casing size and weight

Casing weight determines the gravitational force which pulls the pipe toward the lower side of the borehole. The heavier the casing string is, more or stronger centralizers are required.

3. Fluids inside casing and in annulus

The buoyancy force calculation is further complicated by the multi-fluid configuration during a cementing job. When heavy cement slurries are inside the casing and light drilling mud in the annulus, the effective weight of casing is at its greatest. On the other hand, when cement slurries are in place and displacement fluid inside the casing, the buoyancy is at its peak and the effective weight of the pipe is the least.

When we design the centralizer placement for the scenario of cement slurries in place, it favors us to have less effective casing weight, pulling the casing string downward; but when the cement slurries are inside the casing during the displacement, the lower standoff could cause mud channeling problems. It is better to study standoff for all the situations.

4. Centralizer properties

Not all centralizers are created equal. Centralizer manufacturers are striving to improve the performances of their products.

For solid centralizers including mold-on type, the blade OD is the key parameter as far as the casing centralization is concerned.

For bow-spring centralizers, the restoring force is the measurement of the strength of a centralizer. It is defined as the side force to deflect the bow by 1/3 or its original height.

5. Centralizer placement

Once the well is planned, casing designed, cementing procedure prepared and centralizer type selected, we do not have many options other than placing the centralizers strategically to achieve the desired standoff. However, this is also a great leverage.

Poor spacing will result in poor standoff even with the best centralizers in the market.

Casing Centralizer Series – 2: Standoff

Posted on January 15, 2015 by Gefei Liu, PVI

The term standoff (SO) describes the extent to which the pipe is centered (Fig. 1).

Fig. 1. Definition of standoff

If a casing is perfectly centered, the standoff is 100%. A standoff of 0% means that the pipe touches the wellbore. Regardless of the centralizer type, the goal is to provide a positive standoff, preferably above 67%, throughout the casing string.

The casing deflection between centralizers obeys the laws of physics. An engineering analysis can help both operators and service companies arrive at the optimized number and placement of centralizers for a particular well.

The casing standoff depends on the following factors:

Well path and hole size
Casing OD and weight
Centralizer properties
Position and densities of mud and cement slurries (buoyance)

Incomplete mud removal causes poor cement seal and non-productive time. A good casing standoff helps reduce the mud channeling and improves the displacement efficiency. The following 2 pictures illustrate the impact of casing standoff on displacement efficiency. The 3^rd track in Figure 3 shows the mud concentration in the annulus after a cementing job with 0% casing standoff.

Fig. 2. Displacement Efficiency for Casing Standoff of 0%

You can see that there are some large red areas, which represent the high percentage of the remaining mud, in the narrow side (NS) of an eccentric annulus.

We kept everything else the same and only changed the casing standoff to 70%. Now the displacement efficiency improved significantly, as shown in the following picture.

Fig. 3. Displacement Efficiency for Casing Standoff of 70%

Casing Centralizer Series – 1: Types of Centralizers

Posted on January 13, 2015 by Gefei Liu, PVI

Casing centralizer is a mechanical device secured around the casing at various locations to keep the casing from contacting the wellbore walls. As a result of casing centralization, a continuous annular clearance around the casing allows cement to completely seal the casing to the borehole wall.

Casing centralization is one of the key elements to ensure the quality of a cementing job by preventing mud channeling and poor zonal isolation. Centralizers can also assist in the running of the casing and the prevention of differential sticking.

Centralizer’s usage is extensive! It is estimated that 10 million centralizers are manufactured and used every year globally. Centralizer manufacturers likely want to increase the demand for centralizers. However, operators on the other hand, may wonder: “Should we use that many?”

While centralizers are used extensively, wellbore problems continue to arise due to poor cementing jobs. Centralizer properties and placements directly or indirectly affect the quality of the cementing job.

The challenge that both operators and service companies face is to choose the right type of centralizers and place the right amount at the optimum positions on the casing to achieve a good standoff profile.

There are 4 types of centralizers (Fig. 1): bow-spring, rigid, semi-rigid, and mold-on; each with its own pros and cons.

Fig. 1. Types of centralizers

1. Bow-Spring

Since the bow springs are slightly larger than the wellbore, they can provide complete centralization in vertical or slightly deviated wells. Due to the flexibility of bows, they can pass through narrow hole sections and expand in the targeted locations.

The shape and stiffness of the bows determine the restoring force, which is defined as the resistance force when a bow is compressed by 1/3 of its uncompressed height. The effectiveness of this type of centralizer is heavily dependent on the restoring force.

When the casing is heavy and/or the wellbore is highly deviated, they may not support the casing very well. For example, on a riser tieback casing string, a helically buckled casing could create a side force of 50,000 to 100,000 lbf (222 to 445 kN), well beyond the capabilities of the spring-bow centralizer. A solid centralizer would be able to meet the requirements.

2. Rigid

Rigid centralizers are built out of solid steel bars or cast iron, with a fixed blade height and are sized to fit a specific casing or hole size. This type is rugged and works well even in deviated wellbores, regardless of the side force. They provide a guaranteed standoff and function as bearings during the pipe rotation, but since the centralizers are smaller than the wellbore, they will not provide a good centralization as the bow-spring type centralizers in vertical wells.

3. Semi-Rigid

Semi-rigid centralizers are made of double crested bows, which provide desirable features found in both the bow-spring and the rigid centralizers. The spring characteristic of the bows allows the semi-rigid centralizers to compress in order to get through tight spots and severe doglegs. The double-crested bow provides restoring forces that exceed those standards set forth in the API specifications and therefore exhibits certain features normally associated with rigid centralizers.

4. Mold-On
The mold-on centralizer blades, made of carbon fiber ceramic materials, can be applied directly to the casing surface. The blade length, angle and spacing can be designed to fit specific well applications, especially for the close tolerance annulus. The non-metallic composite can also reduce the friction in extended reach laterals to prevent casing buckling.

Complaints About Your Job? See This Then!

Posted on October 14, 2014 by Gefei Liu, PVI

It’s the last week of September and we are in Calgary, the energy center of Canada. 2 weeks ago a sudden snow struck the city and killed quite a few trees. We can feel that winter is coming slowly into this growing city, both vertical and horizontally.

In 2012, Calgary added to the city its tallest building, “The Bow”, which is 779 feet. From outside, it is a beauty of steel and glass, no sign of concrete whatsoever. This is what we saw the other day when we visited our clients.

From the picture you can see the cleaning crew hanging way up in the air while cleaning the windows. They are probably trying to get the job done before the winter fully arrives. I think there are lots of people that are afraid of heights, so those people must to a certain degree, like such risky jobs, but personally I feel blessed to be able to walk on solid ground and appreciate the job I have.

It is fair to say that none of us have the perfect job. We make tradeoffs here and there and try to have a balance between what we have and what we want. We develop drilling software and this task requires intensive coding. Occasionally, I lose myself in the midst of numerous lines of programming codes and feel like the purpose of the work gets a little fuzzy. Trips like this one help me see how lucky we are and how much we already have and the chance to meet our users is always a plus. Nothing beats to see how our drilling software helps drilling engineers on their daily tasks.

Do I complain about my job? I try not to. Living in a real world, we all have different jobs. The perfect job does not exist because each of us has our own definition of it and even if it does exist, somebody else has it. Maybe the perfect job cannot be found, but is created through a combination of harnessing our potential that not only increases our performance, but brings us more job satisfaction.

We Wear The Watch We Make

Posted on October 1, 2014 by Gefei Liu, PVI

I am not just one of our software developers; I am also a user and so is everyone else on our team. Our insatiable curiosity and passion about drilling engineering and problem solving are the driving force behind delivering our products. Our goal is to save drilling professionals’ time and reduce risks, and if we do it right, we also help ourselves – BONUS!

Software development, specially drilling software development, requires collaboration from a pool of talents, ranging from drilling engineers, mathematicians, programmers and quality control personnel. A good software package is measured not only by the accuracy or comprehensiveness, but also by how easy it is to use it. The gaps between users and developers are always there. We try to bridge that gap by utilizing our own software on our consulting projects.

Using our own software transforms us from developers to decision-makers. We become more sensitive to users’ needs and more careful in our interface design.

It is not always easy, but it is a lot of fun. From every interface design we put into the software, we toss aside dozens more. If we are complaining about the number of clicks to accomplish a task, then the users would too.

The results?

The software we use is the software we develop, in other words, we wear the watch we make.

Hot Game with Hot Model

Posted on August 19, 2014 by Gefei Liu, PVI

A couple of days ago, at 3:30pm, the hottest time of the day, my friend Francisco and I played a match of outdoor tennis for an hour and half, under the unforgiving sun of August and high humidity of Houston.
For the first 30 minutes, I felt great. Then, my legs were not coordinating with my mind. I only won 4 games in 2 sets. But I was proud of myself to be able to survive the heat.
We took breaks and chatted between games. During one of the breaks, while holding his hot iPhone, he shook his head and told me: “You know what, my phone quits working!” Then he read to me the message on his cellphone screen, which said:

Fig.1: HTHP Classification

We started laughing and felt good about ourselves: we were running directly under the sun and the iPhone was sitting in the shadow of the pavilion.

Heat does amazing things to our bodies, helping us warm up or exhaust us. It was my intention to test the strength of my body when exposed under the sun. It was not my best experience, but it served a purpose.

In petroleum industry, the days of easy, cheap oil are over, making it harder to meet demands without any complicated and expensive projects. As operators continue to drill in deeper and more extreme formations, we are facing extreme temperatures, which create detrimental effects to drilling operations.

More often than not, we encounter high temperature and high pressure (HTHP) conditions, which are defined with the following picture.

Fig.2: HTHP Classification

HPHT is currently defined as 20,000 psi and 450°F and ultra-HPHT is typically considered anything above.

When drilling a well, we use drill pipes and other tools including downhole motors, which have rubber parts. The combination of high temperature and pressure, and other tough conditions has a dramatic effect on reducing the drilling tools’ ability to withstand the HPHT conditions. When exposed to high temperatures for extended periods, the rubber parts may deteriorate, causing operational failures. High temperatures also have implications for flow assurance (wax, hydrates, or viscosity), stress analysis, drilling tool temperature tolerance, completion fluid density and cementing, etc.

If we can predict downhole temperatures, we can evaluate the risk involved. The downhole temperature changes as we start the mud circulation bring heat from formations at the bottom of the hole upward and release the heat to cool down the formation in the upper section of a well. Here is a snap shot of a temperature profile in a wellbore, using CTEMP, PVI’s Wellbore Circulation Temperature Model.

Fig. 3: CTEMP - Temperature Profile Along the Wellbore

Predicting the temperature and knowing our limits are necessary for tennis games and drilling operations.

Can You Afford Not To Use Drilling Software?

Posted on July 1, 2014 by Gefei Liu, PVI

We decide to buy things based on the benefits those things may bring to us. Those benefits can be either tangible or intangible. If the tangible benefits are greater than the price, the decision process is easy, or if the benefits give us a perception of peace then we will most likely make the purchase.

Drilling software, in particular, is a product packed with advanced engineering calculations. One can say it is a condensed result of research, an interactive digital toolkit or an expert who never gets tired. It normally takes years of development by a well-trained team.

Setting prices for software packages is challenging because there are many uncertainties involved, such as market size, other similar products, etc. One thing is certain in any drilling software, if successfully used in pre-drilling analysis, it will most likely bring more benefits than the money spent on purchasing it. The cost of drilling an oil and gas well is so high that any non-productive time prevention (NPT) is well worth the spending.

Drilling software provides a good way of identifying potential problems in a drilling design and making good recommendations.

Take an example of casing centralizer placements, the purchase of centralizers is to provide a good casing standoff (>70%) to be better prepared for a cementing job. The standoff profile of a casing in a directional well depends on many parameters such as well path, casing weight, fluid densities, top of cement (TOC), centralizer properties and placement. Our past work experiences can help us select the proper types of centralizers and placement, but for a given well condition, it is best to use computer model to make recommendations for the centralizer usage. The following picture shows the resulting standoff profile with a designed centralizer spacing.

Standoff vs Measured Depth - CentraDesign

Thomas Edison once said: “I shall make electricity so cheap that only the rich can afford to burn candles.”

Nowadays, drilling software has become commonplace. Applying the latest drilling technology includes using the available solutions. Drilling software is like the electricity to light our understanding and design of drilling operations. Can you afford not to use it?

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