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TCP is a strong, noncorrosive, spoolable, lightweight technology which is delivered in long lengths, resulting in a reduction of transportation and installation costs. TCP is installed using small vessels or subsea pallets, significantly reducing CO2 emissions. It is also 100% recyclable. Strohm secured a contract with Total and ExxonMobil for a qualification-testing program for a high-pressure, high-temperature (HP/HT) thermoplastic composite pipe (TCP). The qualification project will create a foundation for further development of this TCP technology for riser applications.
Determined efforts are being exerted to shore up the integrity of high-pressure high temperature (HPHT) gas wells, which includes studying all observed integrity failures and adjusting practices to prevent potential failures from reoccurring. In high-pressure high-temperature gas wells, casing thermal expansion is a challenge that should be considered in order to maintain the integrity of the well and surface equipment. The objective of the paper is to describe observed growth in a HP gas wells in relation to the wellhead temperature and how it behaves after cycling the well and how it can affect the annuli pressures.
As methodology, two elements varying during shutdowns were studied thoroughly to determine the extent of the impact they may have on the integrity of HP gas wells. These elements are pressure and temperature. While the linear increase of the wellhead growth with increasing temperature was apparent, the subsequent actions of shutting in the well to cool down and then reopening it led to further deterioration of the cement and the wellhead growth increased even further. The engineering solutions and stress analysis at surface facilities is designed to overcome the growth allowance.
The main observation looks at the temperature element and its effect on well integrity in that it analyses the temperature impact on the well’s tubulars and links it to the stresses caused to casing cement and the resulting wellhead growth. Study will also provide recommendations on maintaining well integrity and avoiding any further deterioration. The temperature impact was also observed in one of the wells after it was shut in and wellhead sensors were left to record shut-in wellhead pressure and temperature for about 14 hours. This gave a reasonable indication of how fast it takes for the wellhead to cool down to ambient conditions. In the subject well, the wellhead temperature dropped by 50% in about 2 hours.
As result of the study, in detail reasons for increased wellhead growth in HPHT gas wells and how to avoid it. It also gives recommendations on maintaining well integrity and reducing the impact of full contraction of the well’s tubulars during cooling; such as maintaining wells on constant production, minimizing open and shut-in cycling, and reducing the shut-in time duration.
An article presents comparative results of pilot of an innovative blocking pack for well-killing operation – emulsion-suspension system with supercharged nanoparticles (ESS). The ESS is characterized by the following competitive advantages: unlimited compatibility with petroleum reservoir fluids, gases, rocks and well-killing brine, adaptability of specific gravity in a wide range (900-1400 kg/m3), foreseeable rheology, alteration of wettability of rock surface, reversibility of blockage, no harm to downhole equipment, system of oil and gas gathering and environment. The ESS blocking pack pilot was carried out in multifractured horizontal wells under high-pressure (39.5 MPa) and high temperature reservoir conditions (115 °C) of Tortasinskoe oil-gas field, Western Siberia, Russia. The reservoir rock of Tortasinskoe oil-gas field is sandstone, characterized by low permeability (0.001-0.0001
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.
Ruiz, Fernando (ADNOC Onshore) | Al Hadidy, Khaled (ADNOC Onshore) | El Yossef, Bassem (ADNOC HQ) | Hebish, Ayman (ADNOC Onshore) | Negoi, Adrian (ADNOC Onshore) | Hamdy, Ibrahim (ADNOC Onshore) | Al Shamisi, Eisa (ADNOC Onshore) | Al Samahi, Musabbeh (ADNOC Onshore) | Kumar, Rakesh (ADNOC Onshore) | Mizukami, Akio (ADNOC Onshore) | Mandal, Vivekananda (ADNOC Onshore) | Ibrahim, Ahmed (ADNOC Onshore) | Wakka, Turky (ADNOC Onshore) | Al Soliman, Abdulkareem (ADNOC Onshore) | Nunez, Ygnacio (ADNOC Onshore) | Amorocho, Alexander (ADNOC Onshore) | Al Hendi, Mohamed (ADNOC Onshore) | Al Mutawa, Ahmed (ADNOC Onshore)
The proposal of this paper is to share the knowledge learned in this new procedure and techniques implemented in HP/HT Unconventional wells, created by the Unconventional (UC) Drilling Department at Abu Dhabi which involve around ten different services, where each has a high importance and contribution for the collective success of the well at the moment to frac and hence the feasibility of the project.
In order to assure the integrity and accessibility of the Frac String during Plug and Perf hydraulic fracturing operations of one of the toughest rock in Unconventional business worldwide, one procedure has been developed for running operations best practices. Pressure testing the Frac String (FS) during running in hole in stages while in vertical section to sure safe and successful Wireline setting and retrieving nipples plug with more than 30% solids in the system (high mud weight) to guarantee no leak in the string prior reaching total depth (TD). Hanging and testing cross over (XO), assuring compatibility with the wellhead connections. Cementing up to18.7 ppg. Flexible and expandable slurries, cement inside previous casing and apply pressure on surface to avoid gas percolation during the cement setting period. Cleaning out with Coiled tubing (CT) to ensure no obstruction and using different completion fluids for future accessibility. And finally, Pressure testing the Frac string up to 14ksi all are new practices and proven mitigation measures for all assessed risks for hydraulic fracturing operations.
This paper is about sharing this new procedure in Abu Dhabi for having a cemented FS in UC wells High Pressure / High Temperature (HP/HT) with 100% integrity and internal accessibility to run plugs, perforations, logs and be able to apply high surface pressure to frac the tight reservoir in the planned zone, creating the desired permeability for future production.
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.
Understanding of material properties for tubular design under high-pressure/high-temperature (HP/HT) conditions goes well beyond the basics of the classic methods routinely used in the industry. Coupon test results of high-strength tubulars commonly used in HP/HT wells are presented to demonstrate the temperature and strain-rate dependencies of the stress-strain response. Based on the coupon test results, analytical equations and advanced nonlinear Finite Element Analysis (FEA) are used to illustrate the substantial impact that the temperature and rate-dependent material properties have on pipe body and connection performance in HP/HT applications. This paper raises an awareness of the importance of strain-rate effects, and recommendations are made on a few special considerations to account for these effects in well tubular design for elevated temperature applications. In addition, the findings also provide the basis for a critical discussion of the applicable American Society for Testing and Materials (ASTM)/American Petroleum Institute (API) test standards and the need to understand the effect of different strain/loading rates that may be used in material characterization and full-scale testing of tubular products at elevated temperatures. Collectively the information and results presented in the paper are expected to be very useful to the new generation of engineers charged with the tubular design for challenging well applications involving elevated temperature and severe load conditions.
Gabaldon, Oscar (Blade Energy Partners, Ltd.) | Gonzalez Luis, Romar (Blade Energy Partners, Ltd.) | Brand, Patrick (Blade Energy Partners, Ltd.) | Saber, Sherif (Blade Energy Partners, Ltd.) | Kozlov, Anton (Blade Energy Partners, Ltd.) | Bacon, William (Blade Energy Partners, Ltd.)
In high pressure high temperature (HPHT) reservoirs and exploratory wells, especially in deep water, there is a higher degree of uncertainty, which can increase the operational costs due to non-productive time (NPT) and operational problems due to the unpredictable nature of these wells. For these challenging wells with narrow windows, Managed Pressure Drilling (MPD) techniques offer cost-effective tools to increase the odds for achieving well and cost objectives assurance. There are significant benefits from early implementation of MPD in the project life cycle. These benefits include from improving operational efficiency to risk mitigation and safety enhancement. However, there is an enormous potential that many operators have been missing. This is related to the incorporation of MPD as a driver in optimizing the well design, which could greatly increase the possibilities of reaching target depth, and potentially prepare to eliminate one or more casing strings. Current well design process hinges on the ability to manage uncertainties by company or regulatory requirements, such as kick tolerance and safety factors. This work addresses the value added from implementing MPD in early stages in the project life cycle through the analysis of case studies. The cost savings from the impact on the well design are also discussed. This work also presents a in depth discussion on the benefits, and enablers of this approach. Furthermore, it presents considerations by taking advantage of dynamic processes facilitated with MPD. Finally, new guiding criteria to aim to constitute a systematic and integrated approach to ensure well integrity and optimize well design while also considering the operational implications and integral cost benefits is proposed to the industry. This paper represents the initial phase of a compressive long-term project to integrate two main components of well design. These are MPD adaptive well design, and statistical analysis based on variations of load and/or strength.
Cao, Lihu (Tarim Oilfield Company of Petrochina) | Liu, Hongtao (Tarim Oilfield Company of Petrochina) | Zhang, Bo (Tarim Oilfield Company of Petrochina) | Zhang, Hongyuan (China University of Petroleum Beijing) | Kong, Change (Tarim Oilfield Company of Petrochina) | Liu, Wenchao (Tarim Oilfield Company of Petrochina) | Zhang, Anzhi (Tarim Oilfield Company of Petrochina)
Well integrity failure leads to sustaining annular pressure in high temperature and high pressure gas wells. Timely management and evaluation are essential for the safe production and effective measures under such conditions. However, it's difficult for engineers to monitor large numbers of wells located in large area. Therefore, we develop a real-time online system to timely manage and evaluate the integrity of HTHP gas wells to keep safe production and avoid potential accidents.
To develop this system, we build an integrity regulation and database for every stages of HTHP gas wells, including drilling, completion, testing and production. This system has three modules. The first one is to collect production dynamic, formation properties, well structure and strengthen. Second one is to evaluate the potential risk by analyzing well barrier integrity and annular pressure changing trend. Finally, the system provides gas leak path, cement quality, safe annular pressure range and risk level. This system links the oilfield, research institute and field engineers to get timely and effective reaction for the well integrity evaluation and management.
This system has applied to manage and evaluate hundreds of wells in the largest HPHT gas field affiliated to CNPC. The application of this system reduces the cost and burden while improves the management level. This system has developed as a comprehensive well integrity software platform combining data collection, pressure calculation, figure drawing, risk evaluation, report of well condition, statistics of whole filed integrity data and real time monitoring. The annular pressure, production rate, wellhead temperature can be real-time collected and monitored. Once abnormal annular pressure happens, the system can immediately send alert to engineers and administrator. The researchers and engineers can evaluate the risk and integrity status. This system can also provides reliable support to generate a report about how to management gas wells with integrity failure through analyzing the leak path and maximum allowable annular pressure. The figures drawn by the system include well structure, well barrier, leak path, cement quality, risk level matrix, production dynamic curve, allowable annular pressure range and management chart. This drawing makes the well integrity status and management measures vivid for field company administrator, thus helping making rapid and effectively decision.
The system considers every stage of gas wells and combines the function of data collection, pressure calculation, figure drawing, risk evaluation, report of well condition, statistics of filed integrity data and real time monitoring. It makes the work easier and faster for filed engineers. Moreover, it helps filed administrator get comprehensive understanding of well integrity and make reliable decision. The system can also be extended to gas storage and offshore well management.
Ascorbic acid was used to synthesize crystalline starch nanoparticles (CSNP) for the first time. The CSNP was isolated and the influence of the process variables on the physical properties, recovery yield and crystallinity were studied. Rheology of crystalline starch nanofluid (CSNF) was compared with cassava starch (CS) solution and xanthan. Interfacial tension (IFT) of CSNF was studied at various concentration and temperatures. Influence of concentration, temperature, salinity and their interaction with ultrasound were investigated. Sessile drop contact angle method was used to determine the wettability proficiency of CSNF on an initially oil-wet sandstone core. To justify the finding highlighted above, CSNF and CS solution were applied for EOR purposes at reservoir condition. The approaches were efficient in generating sphere-shaped and elongated nanoparticles (50 nm mean diameter) and higher yield of 39%. Increase in concentration, surface area and temperature of CS and CSNF increased viscosity in comparison to decline in viscosity as the temperature increases for xanthan. Increased concentration, salinity and temperature rise of CSNF decreased IFT and altered the wettability of the sandstone core. CSNF increased the oil recovery by 23% and was effective at high temperature high pressure reservoir conditions. The energy consumption and cost estimation has demonstrated that the methods and polymeric nanofluid are cost-effective than traditional methods and products.