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Pragma is bringing the industry’s first 3D metal printed, ultrahigh expansion bridge plug to market, the Aberdeen-based company said in a press release. Its patented M-Bubble bridge plug has successfully completed final lab testing and is due to begin field trials by the end of 2020. Initially targeted at both the plug-and-abandonment (P&A) sector and water shutoff applications, the first M-Bubble addresses a gap in the market for a lower-cost, fast-turnaround, permanent plugging solution, with a high pressure differential (3,000 psi) capability, the company said. The plug can be set without additional cement to save rig time and “waiting-on-cement” time, which can accumulate significant savings for the operator, especially in deeper, extended-reach wells. It also provides barrier-integrity reassurance when there is the possibility of a poor cement bond or cement channeling occurring on the high side of deviated wells, the company added.
Well abandonment has traditionally not been thought of as a crucial part of a well’s life, though it is as much a part of a well’s life cycle as drilling and production. As such, traditional methods of abandoning a well utilizing cement and bridge plugs are still common practice among most operators throughout the world. Recently, however, operators have been challenged to find more cost-effective ways to abandon wells without jeopardizing the sealing integrity and have begun to look for "alternative" abandonment materials. Materials such as resins have been utilized by some as an alternative, but there have not been any major new developments in well abandonment materials for nearly 100 years. Although cement, bridge plugs and resins have their benefits, there are also limitations to their sealing capabilities. Bridge plugs lack a high expansion ratio required in some wells and rely on elastomers to seal, limiting their ability to seal in damaged tubing or open hole environments. Due to the unique properties of bismuth, plugs can be achieved with an expansion ratio of 3:1 and take the shape of the environment they are being set in. Cement is porous and lacks the ability to block gasses from migrating through it while bismuth has no porosity, making it an ideal material for stoping gas migration. Resins must be squeezed into an area and can take days to fully cure before a seal is created as opposed to bismuth which flows in a a well via gravity and solidifies to create a seal in a few hours. This paper will demonstrate a new way to create gas tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed.
Al-Ajmi, Abdullah (Kuwait Oil Company) | Al-Rushoud, Abdulaziz (Kuwait Oil Company) | Al-Naqa, Faisal (Kuwait Oil Company) | Chouhan, Manoj (Kuwait Oil Company) | Al-Mekhlef, Alanoud (Kuwait Oil Company) | Alasoosy, Fawaz (Baker Hughes) | Albohamad, Dalal (Baker Hughes) | Alshab, Mustafa (Baker Hughes) | Ismail, Maizura (Baker Hughes)
A successful cement job is a crucial element of obtaining and maintaining well integrity and ensuring safe and efficient hydrocarbon production. The success of cementation starts with a full understanding of good parameters such as formation characteristics and depends on a properly designed slurry and spacer system.
The most challenging part of cementing a wellbore is cementing one with a low fracture gradient. There's a high risk of formation breakdowns and hole instability if maximum allowable equivalent circulation densities (ECDs) are exceeded. In addition to severe losses and formation damage, the outcome includes inefficient placement of the cement that warrants time-consuming and costly operations to assure zonal isolation.
In Kuwait, first trial of a new generation of an environmentally friendly enhanced aqueous spacer system was used successfully in a highly deviated well for cementing the production casing covering shale formations. This paper discusses the design of the enhanced aqueous system and its technical features and benefits, which helped improve the cement bond and achieve zonal isolation.
During the drilling process of exploratory wells, the formation data is often limited; most of the time drilling engineers must estimate the pore pressure and fracture gradients. This information is critical for designing the drilling fluid, spacers, and cement slurry as to provide the necessary density and rheological properties.
An error in estimating the pore pressure or fracture gradients can induce wellbore instability and lost circulation. If these losses are not controlled, during the cementing job the programmed top of cement (TOC) will not be achieved, zonal isolation will be compromised, and the casing string will not be fully supported. These problems can lead to additional expenses such as remedial jobs, non-productive rig time, use of additional materials, costly logistics, etc.
This paper presents a case history with a critical cementing job in which the operator was drilling an offshore exploratory well in Southern Mexico when an area with constant gas flow with a narrow pore-pressure to fracture-gradient window was encountered. The operator had to increase the density of the drilling fluid, which in turn induced total losses.
The cementing company recommended pumping a unique spacer technology that enabled circulation to be regained while pumping the cementing job. This technology is an ultra-low invasion cementing spacer that creates an impermeable barrier on the face of the formation through differential pressure. This barrier helps to isolate the formation from the total equivalent circulating density (ECD), thus allowing circulation even in situations where the ECD approaches or slightly exceeds the fracture gradient.
Orprasert, Choosak (Mubadala Petroleum) | Prasongtham, Pattarapong (Mubadala Petroleum) | Abu-Jafar, Feras (Mubadala Petroleum) | McManus, Ian (Mubadala Petroleum) | Thanasarnpisut, Viraphon (Schlumberger) | Johri, Ambuj (Schlumberger) | Duong, Anh (Schlumberger) | Shafie Jumaat, Mohd (Schlumberger)
Effective zonal isolation in wellbores with a challenging mud removal environment is well known to be very difficult to achieve. In wells at the technical limits of Non- Aqueous Fluid (NAF) removal prior to cement placement, cement bond quality and hydraulic isolation can be compromised by leaving channels behind the casing, which can result in several long-term well integrity issues. An Interactive Cementing System (ICS) is developed through special experimental methodologies to mitigate mud channeling issues and improve zonal isolation, by immediately interacting with any residual mud channels left in the well after cement is in place, hence reducing the permeability of mud channels and sealing off microannulus gaps.
Casing centralization is considered to have the greatest influence on mud removal efficiency because it directly affects the flow movement on each side of the wellbore. Mud removal has been studied from numerical simulations, laboratory experiments, and field results, and these show that good mud removal can be achieved only when adequate casing standoff is achieved during cementation. In modern wells where there are many operational restrictions and limitations, especially in highly deviated and horizontal wellbores, final cement designs may not allow good casing standoff and thus not all of the best practices for effective mud removal can be applied.
The objective of the innovative cement system is to have a design that interacts with residual mud in the annulus to "fix" the channels, thereby enhancing cement bond quality and zonal isolation. Two detailed case histories of the application of this technology in the development campaign showed visible improvement in cement bond logs using the ultrasonic imaging tool as compared to offset well that was cemented using a conventional cement system. After two successful implementations, the ICS was selected as the cement system of choice for wells with challenging mud removal.
Wang, Kelin (Tarim Oilfield Company of PetroChina) | Liu, Shuang (Tarim Oilfield Company of PetroChina) | Liu, Hongtao (Tarim Oilfield Company of PetroChina) | Zhang, Bo (Tarim Oilfield Company of PetroChina) | Wang, Yan (Tarim Oilfield Company of PetroChina) | Tong, Shikun (China University of Petroleum East China) | Zhang, Hao (Tarim Oilfield Company of PetroChina)
Kuqa Foreland Basin is located in Western China, which has typical HPHT reservoir. The reservoir has 80-146MPa pressure, 120-186℃ temperature, and 5000-8235m depth. Reservoir stimulation is usually necessary to improve production rate due to the low matrix permeability, and maximum pump pressure is up to 136MPa. Considering the high risk of casing collapse and well control during completion, production packer is running in the high density killing mud (1.75-2.3SG). Moreover, it should also satisfy the needs of both fracturing and production operations. These extreme conditions bring serious challenge for the production packer selection and operation. The failures of packer are found in more than 10 wells in the past decade and maximum wellbore intervention time is over 160 days.
To solve the production packer failure, the failure reasons of production packer are divided into three categories by conducting simulation experiment and theory calculation. One is mud precipitation in high temperature, which leads to the blockage of packer piston chamber. Second, the gap between the casing and the packer is only 2.39mm. The rubber is expanded when the fluid friction on the rubber is large enough during the process of killing mud displaced by packer fluid, which may result in the failure of displacement fluid, or even packer setting in advance. Third, the calculated axial force on the packer is lower than the real operation, because it does not consider the additional axial force generated by temperature effect of confined space among multiple packers. As a result, packer selection is not reasonable, resulting in the packer mandrel fracture during fracturing operations.
Based on the major reasons for the production packer failure, some measures were taken. One is to conduct the mud aging test for 7-10 days in the temperature that 10-15℃ above reservoir temperature. The scraping for three times is conducted in the expected setting depth for packer. Second, the displacement flow rate of fluid between packer rubber and casing is controlled under 3m/s. Third, maximum outer diameter of packer is reduced by 2.54mm through redesigning packer structure. Last, the expansion joint is chosen to relieve axial force during multiple-packer fracturing. And the number of shear pin is optimized by balancing packer setting and safety. By taking the above measures, the packer failure problem was effectively controlled and failure ratio is reduced to 2.4% in the 43 wells.
More than one hundred and fifty HPHT wells will be deployed for Kuqa Foreland Basin in the next three years, so the effective control of production packer failures can significantly improve operation efficiency and reduce costs. Meanwhile, these experience and lessons learned from production packer selection and operation may also be useful for the other HPHT gas fields.
Ahmad, Fajer (Kuwait Oil Company) | Khairallah, Eman (Kuwait Oil Company) | Shuber, Hussain (Kuwait Oil Company) | Shastri, Mukesh (Kuwait Oil Company) | Al-Othman, Ahmad (Kuwait Oil Company) | Ramesh, Anish (Kuwait Oil Company) | Al Batani, Abdulla (Kuwait Oil Company) | Al Foudari, Mahmood (Kuwait Oil Company) | Dutta, Tapas (Kuwait Oil Company) | Aly, Mahmoud (Kuwait Oil Company) | Fituri, Mohamed Aiman (Schlumberger) | Rebaud, Paul (Schlumberger) | Alhamad, Nasser (Schlumberger)
Drilling wells in some locations in the Greater Burgan field in Kuwait, can demonstrate significant challenges across the intermediate section. Part of these challenges are combining the carbonate formations with the weak unstable Ahmadi shaley formations at the bottom of the section. This makes it challenging to drilling engineers and difficult to balance between natural mud losses across the carbonate formations and weak shale that requires higher mud weight. Adding to these challenges, the limited surface locations in the field, that forces the well design trajectory to be deviated, which makes the mud window even smaller and shifts it higher. Zonal isolation across this interval adds an additional challenge, as it will prevent gas and liquid to escape from high pressure deeper zones to shallow lower pressure zones and probably to surface, which potentially may cause well integrity issues in the future.
This paper represents a case of formation collapse on a casing prior to cementing operation, how it was detected, how it was handled and how successfully the well was completed.
Cementing of production casing in the Northern Iraq poses challenges to the cement sheath integrity due to mechanical and thermal stresses induced in the well life. The problem is further aggravated due to narrow window between pore pressure and fracture gradient. The acid-prohibitive cement system with improved mechanical properties was developed to mitigate the effect of induced stresses. The job was executed with operational optimization and zonal isolation was achieved.
Based on the operator's well testing and multi-stage high-rate well stimulation plan, the stress modeling was carried out to determine the optimum mechanical properties. The 19.6 ppg heavyweight cement system with a flexible thermoplastic polymer was designed to achieve the required Young's modulus and Poisson's ratio. Since the density and friction pressure hierarchy could not be met due to the narrow window between pore pressure and fracture gradient, therefore, the slurry rheological properties were optimized for effective mud removal. The pumping parameters were adjusted to maintain the primary well control during the cementing operation without compromising displacement efficiency.
The approach was implemented without any operational issues in the 9-7/8" production casing and 7" liner cementing. Following the job completion and waiting-on-cement time, the 9-7/8" casing was successfully pressure tested with a surface applied pressure of 2,000 psi and a well fluid of 1.78 SG. The isolation scanner cement evaluation confirmed the zonal isolation along the open hole of both the 9-7/8" intermediate casing and the 4½" production liner. Finally, the multi-stage high-pressure stimulation operations were performed during the completion/testing stage with no sign of communication between the different zones. The application of heavyweight acid prohibitive flexible slurry helped the operator to isolate the different zones of interest that were less than 10 m apart and retained the integrity of the seal throughout the high-pressure stimulation operation. Well is open to production without any annular pressure, thus, saving the operator's time and cost on the remedial cementing operations.
The proposed solution will help operators to ensure long-term zonal isolation in the HTHP wells which are subjected to dynamic pressure and temperature changes in the post slurry placement phase. The operators can also avoid the time and money on expensive remedial operations.
Al Afeefi, Baraka Said (Schlumberger) | Bong, Saudyano (Schlumberger) | Mustafa, Hammad (ADNOC Offshore) | Kuliyev, Myrat (ADNOC Offshore) | Chitre, Sunil (ADNOC Offshore) | Bazuhair, Ahmed Khalid (ADNOC Offshore) | Anurag, Atul Kumar (ADNOC Offshore) | Dasgupta, Suvodip (Schlumberger) | Sookram, Neil (Schlumberger) | Mosse, Laurent (Schlumberger)
In a green field located in offshore Abu Dhabi, a new well was drilled in an oil-bearing zone and was completed with slotted liner inside a 6-in horizontal drain hole. Abnormally high gas rates were reported during the surface production testing of this well. This paper highlights the unique use of a new pulsed neutron tool combined with an advanced production logging tool for assessment of the well performance and identification of the source of gas breakthrough.
This combination of advanced technology tools with measurements from array flowmeters, optical gas holdup sensors, and a new generation pulsed-neutron tool was deployed in the well to provide reliable flow type, borehole, and formation measurements in a gas environment. A multidisciplinary approach involving production engineering, petrophysics, and well integrity was essential in diagnosing this unexpected issue of high gas production. An integration of the various results from production logging, the pulsed neutron measurements, and open-hole and cement log data has helped in confirming the source of the produced gas.
The acquired production log (PL) data revealed gas entry from the top of the lower completion and no presence of free gas below that depth. The zonal contributions from the horizontal lateral quantified from the acquired data also helped in assessing the productivity of the reservoir. The pulsed neutron log (PNL) measurements were acquired in the second run, which then helped confirm the borehole fluid properties and to identify and quantify the formation fluids. Combining the PNL and PL data helped identify the gas entry point accurately. Based on the integrated data interpretation, it was confirmed that the gas could not originate from the reservoir being produced through the lower completion and that there must be gas channeling downward through channels in the cement behind the casing from a gas reservoir above the oil reservoir.
The unique use of the advanced PNL data and its integration with other log data facilitated the successful identification of the gas source and quantified zonal contributions in a challenging logging environment.
Loss circulation is encountered frequently while drilling fractured carbonate reservoirs in specific field. The field practice was attempting to cure losses and if incurable, drill blind to total depth (TD) followed by run and cementing of the liner. The interval from loss zone to liner top was covered by the cement squeezed from liner top. The require time to try to cure the lost circulation zone plus squeezing cement job was approximately 15 days. Several optimization initiatives were implemented to reduce this time to less than seven days.
There were at least eight round trips carried out in different ways by different operators to complete the operation of attempting to cure the losses and a liner top squeeze. The engineering team evaluated this for potential optimization, first to identify whether or not losses need to be attempted to be cured to save the time lost on unsuccessful attempts. Second, to analyze the lessons learnt and build on that optimization strategy to reduce the number of trips Lastly to rework the cement slurry design to reduce the number of attempts to squeeze liner top.
As such a detailed strategy was formulated regarding when and how to cure losses followed by an optimized procedure for liner top squeeze which saves three round trips. Further, the liner top squeeze operations previously took multiple attempts of squeeze before a successful pressure test was achieved. Based on the lessons learnt, the slurry design was optimized from several aspects including, slurry density, rheology, thickening time and the pumping and displacement procedure was created which helped to reduce the number attempts from six to only one. Another optimization implemented was enabling the loggers perform pressure pass for cement evaluation by the utilization of tractor instead of conventional (Tough Logging Conditions) TLC which not only saved time but also depicted better the condition of cement behind liner. Finally, a robust risk assessment encompassing all possible contingencies for expected issues was incorporated.
The optimized liner top squeeze strategy has been implemented at five wells with 100% success, reducing the overall operation time from more than two weeks to less than one week while improving cement quality behind liner to ensure zonal isolation as per requirements.
This paper provides details of how the cement slurry, operations sequence and tools selection were enhanced well by well based on continuous improvement. Since cementing liners across loss circulation intervals exists in most of the carbonate reservoirs worldwide, this paper will help to achieve better zonal isolation in losses environment with lower cost and lesser time.