Optimizing drilling parameters and drill bit design boosts ROP by 37% in Algerian field

Posted on 08 September 2010

By Zerari Djamel, Chafai Ridha, Nacer Rihani, Sofiane Doudou, National Oilwell Varco; Lamali Rachid, Dhina Okba, Khelif Amar, Sonatrach

Figure 1: The HMD field in Algeria features complex geology, as indicated by the variance in rock strengths and vibration potential.

Figure 1: The HMD field in Algeria features complex geology, as indicated by the variance in rock strengths and vibration potential.

Drilling challenges in the Hassi Messaoud (HMD) oilfield of Algeria have proven to be equal to the magnitude of its production. Historically, wells drilled in this field were vertical, moderate borehole diameters having a long 12 ¼-in. section. In order to increase production and gain a better understanding of the reservoir, Sonatrach Drilling engineering moved to moderately deviated, large-diameter boreholes delivering 1,000 m of drain in the reservoir.

Instead of the conventional 12 ¼-in. vertical section, 1,800 m was drilled in 16-in. diameter. This section consists of abrasive sands, interbedded evaporate/carbonate and sand/claystone formations prone to instability and collapse. In addition, there is a 30-m band of extremely hard dolomite. Rock strengths vary widely from 5 Kpsi to 30 Kpsi.

Since early 2000, Sonatrach and National Oilwell Varco (NOV) have been working as a team to address the challenges presented by the larger hole size. Significant issues included drilling vibrations, slow penetration rates, more trips to TD, severe bit and BHA damage and NPT due to stuck pipe while pulling out of hole.

This article first describes the process by which significant performance improvement was achieved as a result of combining innovative bit design techniques and technologies, BHA optimization, optimization of parameters through BHA dynamics modeling, and formation rock strength analysis.

Figure 2: Formation-by-formation measurements of lateral and torsional vibration.  Analysis of the drilling dynamics data showed that lateral vibration was dominant.

Figure 2: Formation-by-formation measurements of lateral and torsional vibration. Analysis of the drilling dynamics data showed that lateral vibration was dominant.

Secondly, the article discusses optimized techniques introduced to enhance performance in the 16-in. section on rigs that have been recently equipped with VFD-AC top drives and how to properly deal with torque limitation issues. Sonatrach was able to repeatedly set ROP drilling records, as well as consistently make section TD in a single run. The net result was a 37% improvement in rate of penetration.

16-IN. APPLICATION IN HMD

The 16-in. section in the HMD field is a long and demanding application. The interval generally varies between 1,750 m and 1,850 m long and is drilled with an oil-based mud of 1.20-1.25 sg.

The main challenge generally encountered is the unpredictable aspect of the lithologies drilled and the variable compressive strengths of the formations. Other challenges are encountered during drilling, especially vibration issues that cause severe bit and BHA damage. The complexity of the geology in the field is also confirmed by the variance of the hardness and the geological properties of the formations in each area of the field. For instance, it has been shown that the northeast part is one of the softest areas in the HMD field, whereas the northwest is considered as one of the hardest. Figure 1 shows the variances between the different areas of the HMD field in terms of rock compressive strengths and vibration potential.

Figure 3: Lab results from the development of the lateral stability index (LSI), which assumes the bit is generating whirl in response to external forces.

Figure 3: Lab results from the development of the lateral stability index (LSI), which assumes the bit is generating whirl in response to external forces.

Roller cone bits were proposed as a first option to drill the entire 16-in. section in the late ’90s. Multiple trips were necessary to reach the section TD, and ROPs were relatively poor (below 10 m/hr). In the attempt to reduce the number of trips, PDC bits were introduced and resulted in drilling the 16-in. section in one run for the first time.

Building on this achievement and aiming to improve ROP, NOV introduced its first-generation of ultra-wear resistant cutters. This achieved a step change in performance, increasing the average ROP of the field from 10.5 m/hr to 16.33 m/hr, then exceeding the 20 m/hr bar for the first time in 2003. With these new benchmarks set, new drilling issues, such as borehole quality and severe downhole vibration, became major challenges.

It is unclear whether these issues occurred previously, but no efforts were made to combat them, as the only concern had been improving ROP and the rate of success of drilling from shoe to TD in one run. Simple solutions were implemented, such as the addition of string stabilizers and conservative drilling procedures, but with inconsistent thus non-conclusive results. This highlighted the need of in-depth solutions that can be obtained only from thorough optimization studies.

The LSI radar plot shows bit stability around the bit’s face. In blue, a newly designed cutting structure with a maximum value of 10; in green, the current design, LSI was 5.6.

The LSI radar plot shows bit stability around the bit’s face. In blue, a newly designed cutting structure with a maximum value of 10; in green, the current design, LSI was 5.6.

OPTIMIZED TECHNOLOGIES

The first step of the optimization process was data gathering and analysis. Conventional sources of data, such as drilling data, logging data and bit records, provide good information on drilling performance but very little on the drilling dynamics that help to identify and measure vibration experienced while drilling. Knowing that, Sonatrach decided to use NOV’s downhole dynamics recorder and associated optimization service to improve understanding of the application. Figure 2 shows measurements obtained in terms of lateral and torsional vibration formation by formation.

Analysis of the drilling dynamics data has shown that lateral vibration is the dominant mode of vibration and was most likely responsible for the early mechanical damage to the cutting structure of the drill bits and poor hole quality. Torsional vibration was present but was less problematic except in certain formations, such as the Neocomian and the Malm formations.

To achieve the objective of reducing vibrations in order to improve performance and borehole quality, NOV was tasked to work with Sonatrach to create a specific design for the 16-in. application for the HMD field.

After assessing the data gathered, it was established that the main areas that needed to be focused on were lateral stability, aggressivity and durability.

1. LATERAL STABILITY: A TOTALLY NEW APPROACH

A new and unreleased method of producing laterally stable PDC bits known as lateral stability index (LSI) was implemented in the new design. The new method assumes the bit is generating whirl in response to external forces, such as BHA side force and interbedded formations, while traditional stability methods assume that whirl is solely bit-generated.

Figure 5: Drilling response ROP vs WOB predicts the new cutting structure (blue) will be faster than the current design.

Figure 5: Drilling response ROP vs WOB predicts the new cutting structure (blue) will be faster than the current design.

The LSI method was developed based on extensive laboratory (Figure 3) and field testing. The aim to develop such a design methodology was to have a fast and accurate prediction of the relative lateral stability of bit designs.

The radar LSI plot gives the stability of the bit around its face as shown in Figure 4. The new cutting structure displayed a max LSI value of 10, compared with the existing product, whose value was 5.6.

2. AGRESSIVITY: ALWAYS FASTER

Cutter size, profile, density and backrake were modified in the new design and optimized to improve the rate of penetration in all formations, especially in the bottom carbonate section (Malm and Dogger Lagunaire formations).

Using the proprietary HYDI (Hycalog Dynamic Investigation) software, aggressivity of the new structure was assessed against the existing cutting structure and was predicted to be faster and more efficient (Figure 5).

Figure 6: Wear prediction plot showing a lower wear number for the new cutting structure (blue), which means it was expected to be more durable than the previous design.

Figure 6: Wear prediction plot showing a lower wear number for the new cutting structure (blue), which means it was expected to be more durable than the previous design.

3. DURABILITY: 1,800 M TO DRILL IN ONE RUN

The new cutting structure had to survive the entire section and stay sharp to maximize drilling efficiency in the difficult bottom part of the section, as well as survive some abrasive intervals of sand and hard dolomite stringers. This would guarantee consistent shoe-to-shoe performance with the highest possible ROP.

Using wear prediction from HYDI software, the new cutting structure showed a lower wear number, and therefore was predicted to be more durable (Figure 6).

Figure 7:  Critical RPM ranges and safe zones in terms of lateral and torsional stability for the HMD field. The green line shows the safe zone in terms of lateral and torsional stability. Applying RPM values higher than 125 rpm represented a safe zone for the bit and an optimized ROP performance until the Malm formation was encountered. After that, increasing RPM with values more than 180 rpm was found to optimize ROP and minimize torsional vibration from the Malm formation to TD.

Figure 7: Critical RPM ranges and safe zones in terms of lateral and torsional stability for the HMD field. The green line shows the safe zone in terms of lateral and torsional stability. Applying RPM values higher than 125 rpm represented a safe zone for the bit and an optimized ROP performance until the Malm formation was encountered. After that, increasing RPM with values more than 180 rpm was found to optimize ROP and minimize torsional vibration from the Malm formation to TD.

From testing to commercialization, the process took several months, and two iterations were necessary using the same design philosophy to reach the optimum solution. The exposure and profile, as well as backrake and density, were revised as soon as data for the first iteration became available. From thorough dull and drilling data analysis, the optimization team quickly identified and implemented needed changes for the second version, which has become the top performer in the HMD field to date.

In addition to the new 16-in. bit design TFX913, Sonatrach and NOV worked on other important factors affecting performance and stability. BHA was the first factor considered. Many studies have been conducted in the past on BHAs, including studies with NOV’s downhole drilling dynamics data recorder. It was concluded that the packed-hole BHA (one near-bit and two string stabilizers) gave the best performance. However, close offset wells using the same bit/BHA configuration resulted in significant performance variations. Thus, BHAs used were compared item by item to verify any differences in lengths and/or configuration.

Figure 8: ROPs improved by 37% over the past decade in the HMD field.

Figure 8: ROPs improved by 37% over the past decade in the HMD field.

It was found that the near-bit stabilizers used varied significantly between BHAs. 1/16-in. under-gauge near-bit stabilizers with 100% wrap and bottom neck between 30 cm and 50 cm gave the best performances and reduced both torsional and lateral vibration.

In terms of drilling parameters, the goal was to look at RPM ranges that may have looked excessive with previous bit technologies, in order to improve ROP further while maintaining bit/BHA stability. The BHA was modeled using NOV’s drillstring dynamics modeling software to make sure that higher RPMs to be experimented were not critical RPMs that are likely to result in detrimental lateral or torsional vibrations (Figure 7). RPM ranges selected using this method resulted in better ROPs, among them the three best performances in the HMD field, with 27.10 m/hr, 29.42 m/hr and recently the new ROP record with 31.84 m/hr.

PERFORMANCE

During the last decade, new drill bit design, in conjunction with in-depth recommendations on BHAs and drilling parameters, have helped to make significant improvements in terms of ROP, borehole quality and shoe-to-TD rate of success in the HMD field. The cost per meter was reduced significantly over this period. Figure 8 shows ROP was improved by 37% while cost per meter was reduced by 40% during the last decade.

Figure 9: In the Berkine field, Well 2 set a field ROP record by optimizing the 16-in. section, and Well 4 broke the Algerian ROP record.

Figure 9: In the Berkine field, Well 2 set a field ROP record by optimizing the 16-in. section, and Well 4 broke the Algerian ROP record.

This success was recognised by other operators in Algeria (Sonatrach associates) drilling in other fields, which have called NOV to apply the same methodical process to 16-in. optimization. One of the best examples was in the Berkine field with a major Sonatrach associate. After only two wells, a new field ROP record was achieved. On the fourth well, the Algerian ROP record was smashed with 39.8 m/hr, 15% faster than the previous Algerian ROP record (Figure 9).

WHAT’S NEXT?

Despite the improvements achieved during the past couple of years, the 16-in. section in the HMD field remains one of the most difficult applications in the world. New challenges have appeared recently, such as torque limitations resulting from the introduction of AC VFD top drives and formation washouts resulting in high torque and difficulty to drilling ahead. Sonatrach and NOV are already working on finding drilling solutions using the same methodology that has proven successful. Amongst the solutions are:

• Introduction of high torque performance downhole motors to provide more torque at the bit;

Figure 10: Rotary drilling subs with 360° circumferential borehole contact were used instead with the 16-in. TFX913 bit to reduce washouts and improve borehole quality.

Figure 10: Rotary drilling subs with 360° circumferential borehole contact were used instead with the 16-in. TFX913 bit to reduce washouts and improve borehole quality.

• Rotary drilling subs with 360° circumferential borehole contact used instead of near-bit stabilizers to reduce washouts and improve borehole quality (Figure 10);

• New drill bit designs incorporating the latest PDC cutter technology and torque control features to improve ROPs on AC VFD top drive rigs.

This article is based on a presentation at the IADC Drilling Africa Conference & Exhibition, 20-21 October 2010, London.

Zerari Djamel is advanced drilling solutions manager for National Oilwell Varco.

HYDI is a trademark of National Oilwell Varco.

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