Successful Application of a Reinforced Composite Mat Pill Technology for Lost Circulation Control in the Norwegian Continental Shelf

2021 ◽  
Author(s):  
Jose A. Barreiro ◽  
John S. Knowles ◽  
Carl R. Johnson ◽  
Iain D. Gordon ◽  
Lene K. Gjerde
Keyword(s):  
Continental Shelf ◽  
Flow Rate ◽  
Drilling Fluid ◽  
Significant Loss ◽  
Lessons Learned ◽  
Cement Slurry ◽  
Lost Circulation ◽  
Reinforced Composite ◽  
Zonal Isolation ◽  
Norwegian Continental Shelf

Abstract An operator in the Norwegian continental shelf (NCS) required sufficient zonal isolation around a casing shoe to accommodate subsequent targeted injection operations. Located in the Ivar Aasen field, and classified as critical, the well had a 9 ⅝-in. casing shoe set in the depleted Skagerrak 2 reservoir. The lost circulation risk was high during cementing because the Hugin formation, located above the reservoir, contained 40 m [~ 131.2 ft] of highly porous and permeable sandstone. During previous operations in the field, lost circulation was observed before and during the casing running and cementing operations. After unsuccessful attempts to cure the losses with various lost circulation materials, a new solution was proposed to target the specific lost circulation problem by combining two types of reinforced composite mat pill (RCMP) technology. Specifically, the first type of RCMP technology was engineered for use in the viscous preflush spacer, and the second was applied to the cement slurry itself. Working in synergy, the RCMP systems mitigated the risk of incomplete zonal isolation. With no losses observed upon reaching total depth (TD) for the 12 ¼-in. hole, the 9 ⅝-in. casing was run with a reamer shoe and 15 rigid centralizers. Between 2700 and 2728 m [~ 8,858 and 8,950 ft] measured depth (MD), the rig observed constant drag of 30 to 40 MT whilst working the casing down, and circulation was completely lost before partial returns were eventually observed. The rig continued to work the string down to the planned landing depth at 3897 m [~ 12,785 ft] MD. Precementing circulation ensued with staged pump rates increasing at 100-L/min [~ 0.6-bbl/min] intervals up to 1400 L/min [~ 8.8 bbl/min], which induced losses at a rate of 6.5 m3/hour [~ 40 bbl/hour]). Subsequently, the flow rate was reduced to 1300 L/min [~ 8.1 bbl/min], and the annular volume was circulated 2.6 times with full returns. Attempts to reduce equivalent circulating density (ECD) ahead of the cementing operation were implemented at 1300 L/min [~ 8.1 bbl/min] using a low-density, low-rheology oil-based drilling fluid pill. However, a significant loss rate of 18.0 m3/hour [~113 bbl/hour] was observed. The flow rate was reduced to 950 L/min [~ 6.0 bbl/min], and partial circulation was recovered. After the spacer and cement had reached the annulus, full returns were immediately observed and continued until the top plug was successfully bumped. Acoustic logging determined that the operation had achieved the primary job objective of establishing the required length of hydraulically isolating cement in the annulus. Lost circulation is a costly problem that can be difficult to solve, even with the wide variety of technologies available (Vidick, B., Yearwood, J. A., and Perthuis, H. 1988. How To Solve Lost Circulation Problems. SPE-17811-MS). This case study demonstrates a successful solution. The operator will be able to incorporate lessons learned and best practices into future operations, and these lessons and practices will be useful to other operators with similar circumstances.

The Research and Application of Cementing Isolation Technology in High Porosity and Permeability of Developed Clastic Rock Reservoir in Tarim Basin

2021 ◽  
Author(s):  
Hongtao Liu ◽  
Zhengqing Ai ◽  
Jingcheng Zhang ◽  
Zhongtao Yuan ◽  
Jianguo Zeng ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Water Layer ◽  
High Porosity ◽  
Self Healing ◽  
Cement Slurry ◽  
Clastic Rock ◽  
Pump Rate ◽  
Porosity And Permeability ◽  
Zonal Isolation ◽  
High Pump

Abstract The average porosity and permeability in the developed clastic rock reservoir in Tarim oilfield in China is 22.16% and 689.85×10-3 μm2. The isolation layer thickness between water layer and oil layer is less than 2 meters. The pressure of oil layer is 0.99 g/cm3, and the pressure of bottom water layer is 1.22 g/cm3, the pressure difference between them is as bigger as 12 to 23 MPa. It is difficult to achieve the layer isolation between the water layer and oil layer. To solve the zonal isolation difficulty and reduce permeable loss risk in clastic reservoir with high porosity and permeability, matrix anti-invasion additive, self-innovate plugging ability material of slurry, self-healing slurry, open-hole packer outside the casing, design and control technology of cement slurry performance, optimizing casing centralizer location technology and displacement with high pump rate has been developed and successfully applied. The results show that: First, the additive with physical and chemical crosslinking structure matrix anti-invasion is developed. The additive has the characteristics of anti-dilution, low thixotropy, low water loss and short transition, and can seal the water layer quickly. Second, the plugging material in the slurry has a better plugging performance and could reduce the permeability of artificial core by 70-80% in the testing evaluation. Third, the self-healing cement slurry system can quickly seal the fracture and prevent the fluid from flowing, and can ensuring the long-term effective sealing of the reservoir. Fourth, By strict control of the thickening time (operation time) and consistency (20-25 Bc), the cement slurry can realize zonal isolation quickly, which has achieved the purpose of quickly sealing off the water layer and reduced the risk of permeable loss. And the casing centralizers are used to ensure that the standoff ratio of oil and water layer is above 67%. The displacement with high pump rate (2 m3/min, to ensure the annular return velocity more than 1.2 m/s) can efficiently clean the wellbore by diluting the drilling fluid and washing the mud cake, and can improve the displacement efficiency. The cementing technology has been successfully applied in 100 wells in Tarim Oilfield. The qualification rate and high quality rate is 87.9% and 69% in 2019, and achieve zone isolation. No water has been produced after the oil testing and the water content has decreased to 7% after production. With the cementing technology, we have improved zonal isolation, increased the crude oil production and increased the benefit of oil.

Implementation of Factory Cementing Concept in the High-Intensity Drilling Environment of Khazzan, Sultanate of Oman

2021 ◽  
Author(s):  
Emmanuel Therond ◽  
Yaseen Najwani ◽  
Mohamed Al Alawi ◽  
Muneer Hamood Al Noumani ◽  
Yaqdhan Khalfan Al Rawahi ◽  
...  
Keyword(s):  
Shallow Water ◽  
High Intensity ◽  
Sultanate Of Oman ◽  
Cement Slurry ◽  
Short Term ◽  
Lost Circulation ◽  
Well Integrity ◽  
Sustained Casing Pressure ◽  
Zonal Isolation ◽  
Casing Pressure

Abstract The Khazzan and Ghazeer gas fields in the Sultanate of Oman are projected to deliver production of gas and condensate for decades to come. Over the life of the project, around 300 wells will be drilled, with a target drilling and completion time of 42 days for a vertical well. The high intensity of the well construction requires a standardized and robust approach for well cementing to deliver high-quality well integrity and zonal isolation. The wells are designed with a surface casing, an intermediate casing, a production casing or production liner, and a cemented completion. Most sections are challenging in terms of zonal isolation. The surface casing is set across a shallow-water carbonate formation, prone to lost circulation and shallow water flow. The production casing or production liner is set across fractured limestones and gas-bearing zones that can cause A- and B-Annulus sustained casing pressure if not properly isolated. The cemented completion is set across a high-temperature sandstone reservoir with depletion and the cement sheath is subjected to very high pressure and temperature variations during the fracturing treatment. A standardized cement blend is implemented for the entire field from the top section down to the reservoir. This blend works over a wide slurry density and temperature range, has expanding properties, and can sustain the high temperature of the reservoir section. For all wells, the shallow-water flow zone on the surface casing is isolated by a conventional 11.9 ppg lightweight lead slurry, capped with a reactive sodium silicate gel, and a 15.8 ppg cement slurry pumped through a system of one-inch flexible pipes inserted in the casing/conductor annulus. The long intermediate casing is cemented in one stage using a conventional lightweight slurry containing a high-performance lost circulation material to seal the carbonate microfractures. The excess cement volume is based on loss volume calculated from a lift pressure analysis. The cemented completion uses a conventional 13.7 - 14.5 ppg cement slurry; the cement is pre-stressed in situ with an expanding agent to prevent cement failure when fracturing the tight sandstone reservoir with high-pressure treatment. Zonal isolation success in a high-intensity drilling environment is assessed through key performance zonal isolation indicators. Short-term zonal isolation indicators are systematically used to evaluate cement barrier placement before proceeding with installing the next casing string. Long-term zonal isolation indicators are used to evaluate well integrity over the life of the field. A-Annulus and B-Annulus well pressures are monitored through a network of sensors transmitting data in real time. Since the standardization of cementing practices in the Khazzan field short-term job objectives met have increased from 76% to 92 % and the wells with sustained casing pressure have decreased from 22 % to 0%.

Obtaining Zonal Isolation in Geothermal Wells

2021 ◽  
Author(s):  
Allam Putra Rachimillah ◽  
Cinto Azwar ◽  
Ambuj Johri ◽  
Ahmed Osman ◽  
Eric Tanoto
Keyword(s):  
Best Practices ◽  
Oil And Gas ◽  
Lessons Learned ◽  
Free Fluid ◽  
High Heating Rate ◽  
Lost Circulation ◽  
Geothermal Well ◽  
Geothermal Wells ◽  
Zonal Isolation ◽  
Primary Cementing

Abstract Cementing is one of the sequences in the drilling operations to isolate different geological zones and provide integrity for the life of the well. As compared with oil and gas wells, geothermal wells have unique challenges for cementing operations. Robust cementing design and appropriate best practices during the cementing operations are needed to achieve cementing objectives in geothermal wells. Primary cementing in geothermal wells generally relies on a few conventional methods: long string, liner-tieback, and two-stage methods. Each has challenges for primary cementing that will be analyzed, compared, and discussed in detail. Geothermal wells pose challenges of low fracture gradients and massive lost circulation due to numerous fractures, which often lead to a need for remedial cementing jobs such as squeeze cementing and lost circulation plugs. Special considerations for remedial cementing in geothermal wells are also discussed here. Primary cement design is critical to ensure long-term integrity of a geothermal well. The cement sheath must be able to withstand pressure and temperature cycles when steam is produced and resist corrosive reservoir fluids due to the presence of H2S and CO2. Any fluid trapped within the casing-casing annulus poses a risk of casing collapse due to expansion under high temperatures encountered during the production phase. With the high heating rate of the geothermal well, temperature prediction plays an important part in cement design. Free fluid sensitivity test and centralizer selection also play an important role in avoiding mud channeling as well as preventing the development of fluid pockets. Analysis and comparison of every method is described in detail to enable readers to choose the best approach. Massive lost circulation is very common in surface and intermediate sections of geothermal wells. On numerous occasions, treatment with conventional lost-circulation material (LCM) was unable to cure the losses, resulting in the placement of multiple cement plugs. An improved lost circulation plug design and execution method are introduced to control massive losses in a geothermal environment. In addition, the paper will present operational best practices and lessons learned from the authors’ experience with cementing in geothermal wells in Indonesia. Geothermal wells can be constructed in different ways by different operators. In light of this, an analysis of different cementing approaches has been conducted to ensure robust cement design and a fit-for-purpose cementing method. This paper will discuss the cementing design, equipment, recommendations, and best available practices for excellence in operational execution to achieve optimal long-life zonal isolation for a geothermal well.

The Theory and the Practical Validation of the Fluid Level Position in the Annulus During Lost Circulation

2021 ◽  
Author(s):  
Alexey Ruzhnikov ◽  
Edgar Echevarria
Keyword(s):  
Flow Rate ◽  
Drilling Fluid ◽  
Time Interval ◽  
Fluid Level ◽  
Drilling Tool ◽  
Lost Circulation ◽  
Hole Pressure ◽  
Bottom Hole Pressure ◽  
Bottom Hole ◽  
Carbonate Formations

Abstract Carbonate formations around the world and specifically in a Middle East are prone to have total losses while drilling. And the nature of the losses often related to the highly fractured formations of the pay zone. When such fracture(s) is crossed by the wellbore the lost circulation initiated and led to a drilling without a return to a surface. To avoid undesired well control event or wellbore instability and to maintain the constant bottom hole pressure the mud cap drilling strategy often used as a preventative measure. The mud cap can be either the continuous or based on some volume or time interval, depends on the local practices or the policy of an operator. The mud cap flow rate as well as mud cap mud weight are often based on the best practices, not supported by an engineering study. To understand the behavior of the drilling fluid level in the annulus while drilling with total losses the drilling bottom hole assembly equipped with annular pressure while drilling tool was used. As the drilling required to use the continuous mud cap, then the specific guideline was developed on measurement of the bottom hole pressure and further conversion of it to the fluid level. The study was performed across pay zone with one or several loss circulation zones identified. As the result it was confirmed that the used mud cap flow rate had minor to none effect on the fluid level position in the annulus and that the bottom hole pressure remained the same. It showed as well that different loss zones are behaving in a different way, what can be considered as a factor affecting their ability to be sealed. The obtained knowledge and the information should help to understand better the loss circulation behavior as well be an important step toward development of the product which may cure the losses in high fractured carbonate formations. The results of the study can be implemented in any other project or a field.

Engineered Composite Lost Circulation Solution to Successfully Cure Total Losses During Drilling Across Naturally Fractured Formations in Ghawar Gas Field, Saudi Arabia

2021 ◽  
Author(s):  
Faizan Ahmed Siddiqi ◽  
Carlos Arturo Banos Caballero ◽  
Fabricio Moretti ◽  
Mohamed AlMahroos ◽  
Uttam Aswal ◽  
...  
Keyword(s):  
Saudi Arabia ◽  
Circulation System ◽  
Cement Slurry ◽  
Fiber System ◽  
Gas Field ◽  
Well Control ◽  
Lost Circulation ◽  
Carbonate Formation ◽  
Naturally Fractured ◽  
Zonal Isolation

Abstract Lost circulation is one of the major challenges while drilling oil and gas wells across the world. It not only results in nonproductive time and additional costs, but also poses well control risk while drilling and can be detrimental to zonal isolation after the cementing operation. In Ghawar Gas field of Saudi Arabia, lost circulation across some naturally fractured formations is a key risk as it results in immediate drilling problems such as well control, formation pack-off and stuck pipe. In addition, it can lead to poor isolation of hydrocarbon-bearing zones that can result in sustained casing pressure over the life cycle of the well. A decision flowchart has been developed to combat losses across these natural fractures while drilling, but there is no single solution that has a high success rate in curing the losses and regaining returns. Multiple conventional lost circulation material pills, conventional cement plugs, diesel-oil-bentonite-cement slurries, gravel packs, and reactive pills have been tried on different wells, but the probability of curing the losses is quite low. The success with these methods has been sporadic and shown poor repeatability, so the need of an engineered approach to mitigate losses is imperative. An engineered composite lost-circulation solution was designed and pumped to regain the returns successfully after total losses across two different formations on a gas well in Ghawar field. Multiple types of lost-circulation material were tried on this well; however, all was lost to the naturally fractured carbonate formation. Therefore, a lost-circulation solution was proposed that included a fiber-based lost-circulation control (FBLC) pill, composed of a viscosifier, optimized solid package and engineered fiber system, followed by a thixotropic cement slurry. The approach was to pump these fluids in a fluid train so the FBLC pill formed a barrier at the face of the formation while the thixotropic cement slurry formed a rapid gel and quickly set after the placement to minimize the risk of losing all the fluids to the formation. Once this solution was executed, it helped to regain fluid returns successfully across one of the naturally fractured zones. Later, total losses were encountered again across a deeper loss zone that were also cured using this novel approach. The implementation of this lost-circulation system on two occasions in different formations has proven its applicability in different conditions and can be developed into a standard engineered approach for curing losses. It has greatly helped to build confidence with the client, as it contributed towards minimizing non-productive time, mitigated the risk of well control, and assisted in avoiding any remedial cementing operations that may have developed due to poor zonal isolation across certain critical flow zones.

scholarly journals Research on Overflow Monitoring Mechanism Based on Downhole Microflow Detection

2014 ◽  
Vol 2014 ◽  
pp. 1-6 ◽  
Author(s):  
Liang Ge ◽  
Ze Hu ◽  
Ping Chen ◽  
Lei Shi ◽  
Qing Yang ◽  
...  
Keyword(s):  
Flow Rate ◽  
Flow Measurement ◽  
Drilling Fluid ◽  
Rate Variation ◽  
Lost Circulation ◽  
Bottom Hole ◽  
Managed Pressure Drilling ◽  
Type Flow ◽  
Drilling System ◽  
The Cost

The flow rate variation of the drilling fluid and micro-overflow loss is difficult to analyze. The purpose to prevent the occurrence of kick, lost circulation, and other complex conditions is not easy to be achieved. Therefore, the microflow-induced annulus multiphase flow rate and annulus pressure field model were studied, and a downhole microflow measurement system has been developed. A differential pressure type flow measurement was used in the system, and real-time downhole information was obtained to achieve deep, narrow windows and other safety-density complex formation security. This paper introduced a new bottom-hole flow meter which can measure the annular flux while drilling and monitor overflow and circulation loss. The accuracy and reliability of the MPD (managed pressure drilling) system can be improved obviously by applying the device; as a result, the safety of drilling is enhanced and the cost is reduced.

Hollow Glass Spheres HGS in Drilling Fluid: Case Study of Preventing and Mitigating Total Losses

2021 ◽  
Author(s):  
Vitaly Sherishorin ◽  
Martin Rylance ◽  
Yevgeniy Tuzov ◽  
Olga Krokhaleva ◽  
Evgeny Tikhonov ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Scale Up ◽  
Cost Savings ◽  
Field Application ◽  
Lessons Learned ◽  
Drilling Fluids ◽  
Lost Circulation ◽  
Initial Application ◽  
General Plan ◽  
Effective Manner

Abstract The paper describes the first deployment of HGS in Eastern Siberia as a mud additive. The technology was utilized for reducing drilling fluid density for prevention and mitigation of losses; while drilling through a producing reservoir section with low pore pressure, unconsolidated and fractured sands. The engineering considerations, fundamentals of the approach and major risks involved were reviewed with application to the Sredneboutobinskoye Oilfield as a pilot field application for broader future plans. Key planning, delivery and execution principles of the initial application will be reported in the paper. Initially deployed on three wells, including multi-laterals (Rylance et al., 2021), the paper will walk through the engineering considerations during the planning and execution phases. Key sections include the data gathered and the many lessons learned during the incremental and stepwise deployment. The paper will also report on post drilling productivity and comparisons with the offset wells drilled with conventional mud systems, which suffered severe losses. The results of this pilot have exceeded expectations. There have been many insights and the Team are now looking to set a timetable to scale-up across the Taas-Yuryakh Neftegazodobycha (TYNGD). After many hours of laboratories study and preparation works, the general plan was to reduce the static density and ECD to mitigate fluid losses. However, the applied results showed additional effects from HGS. Data will be provided that demonstrated loss-free drilling was achieved where this had not been the case before, with a material reduction in NPT, lost circulation material (LCM) needs and costs. Much has been learned, recovered HGS material has been demonstrated to be an effective LCM pill and centralization of mud processing may offer additional cost savings and improvements. Further efficiencies are also expected to be achieved and future potential is considerable. HGS for cementing is well documented, yet application for drilling fluids has been less well reported and almost exclusively related to single wells. The TYNGD application is innovative as this is a major development with 10 active drilling rigs. The application is on multi-laterals and offset wells are available for direct comparison. The results of the approach demonstrate a new way of performing well construction in an effective manner for major field developments where losses are prevalent.

Comparative experimental evaluation of drilling fluid contamination on shear bond strength at wellbore cement interfaces

2014 ◽  
Vol 11 (6) ◽  
pp. 597-604 ◽  
Author(s):  
Mileva Radonjic ◽  
Arome Oyibo
Keyword(s):  
Bond Strength ◽  
Shear Bond Strength ◽  
Oil And Gas ◽  
Drilling Fluid ◽  
Cement Slurry ◽  
Geothermal Wells ◽  
Sustained Casing Pressure ◽  
Zonal Isolation ◽  
Casing Pressure ◽  
The Impact

Wellbore cement has been used to provide well integrity through zonal isolation in oil and gas wells as well as geothermal wells. Failures of wellbore cement result from either or both: inadequate cleaning of the wellbore and inappropriate cement slurry design for a given field/operational application. Inadequate cementing can result in creation of fractures and microannuli, through which produced fluids can migrate to the surface, leading to environmental and economic issues such as sustained casing pressure, contamination of fresh water aquifers and, in some cases, well blowout. To achieve proper cementing, the drilling fluid should be completely displaced by the cement slurry, providing clean interfaces for effective bond. This is, however, hard to achieve in practice, which results in contaminated cement mixture and poor bonds at interfaces. This paper reports findings from the experimental investigation of the impact of drilling fluid contamination on the shear bond strength at the cement-formation and the cement-casing interfaces by testing different levels of contamination as well as contaminations of different nature (physical vs. chemical). Shear bond test and material characterization techniques were used to quantify the effect of drilling fluid contamination on the shear bond strength. The results show that drilling fluid contamination is detrimental to both cement-formation and cement-casing shear bond strength.

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