The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract Geologic carbon sequestration may involve injection of large quantities of carbon dioxide (CO2) into primarily deep saline aquifers for storage purposes or, where feasible, into oil and gas reservoirs for enhanced oil recovery objectives. The literature and experience from industrial analogs indicates that well-bores (active or inactive/abandoned) may represent the most likely route for leakage of injected CO2 from the storage reservoirs. Therefore, sound CO2 injection well design and well integrity, operation and monitoring are of critical importance in such projects. This paper presents design considerations for (1) the construction of CO2 injection wells including down-hole tubular (casing/tubing/packer) and cements, (2) methods to verify that the wells have mechanical integrity (both internal and external) and monitoring approaches applicable to CO2 geo-sequestration in the U.S. and a short discussion of the risks posed by abandoned wells within a storage field and the safety aspect of CO2 wells.
Abstract Achieving long term well integrity in deep gas wells offshore Abu Dhabi has presented some unique challenges. Historically, cases of poor zonal isolations has led to pressures in annuli and even sea-bed seepages. In one case this had caused well-head movement, causing concerns about the integrity of well-head platforms and surface equipment. Corrective actions to remedy failures has cost the operator millions of dollars in addition to taking up valuable resources and rig-time. The challenges were to ensure proper zonal isolations in these deep gas wells, where several stacked reservoirs have to be drilled prior to the target Khuff reservoir. Well-bore instability in shale formations and lost circulations into weaker, fractured carbonates presented significant complications, which seriously impacted the efforts of achieving zonal isolations in the multiple reservoirs. Thus, an integrated approach was undertaken to overcome these challenges. This encompassed well and casing design, drilling fluids formulations, cement designs, fit-for-purpose equipment, in addition to maintaining a stable well-bore and addressing the loss circulation issues that effectively raised the fracture gradients of weaker formations. The paper provides an overview of the optimization processes involved in the successful planning and execution of the wells. The paper describes the development and application of drilling fluids for different hole sections to achieve well-bore stability as well as mitigation of lost circulation incidents. The particular fluids technique used to strengthen the weaker formations resulted in the ability to place the cement slurries in the well-bore as designed. As described in the case histories, the adaptation and application of various fluid technologies to arrive at fit-for-purpose solutions and the engineering of the total integrated drilling and cementing fluids solution was crucial in achieving the necessary zonal isolations to ensure long-term well integrity of the gas producer and injector wells.
Abstract Mud removal and cement placement during a cementing operation are key factors to ensuring zonal isolation. Actual well testing results show that majority of wells have zonal communication during the life of production. The communication between water and oil zones may significantly affect oil production and require expensive remedial squeeze treatments. Fully understanding the flow characteristics and interactive behaviors in mud, spacer, and cement is an important step to ensure critical zonal isolation. A newly developed computational fluid dynamics model helps end users better understand the transport phenomena of intermixing multiple fluids. Fluid decay resulting from the intermixing involving the mud, spacer, and cement systems is quantified for given downhole conditions of wellbore geometry, fluid properties, pump rates and casing centralization. The robust method allows the analysis of potential hydrocarbon production zonal isolation success and optimization of cement placement. This advanced fluid displacement simulator has been field verified with impressive results for a wide range of annuli. A recently developed pseudo 3-D visualization module aids in understanding the complex phenomena as well. Some field cases used for verification are included. The detailed job analysis demonstrates the methodology used to study the effects of fluid systems, pump rates, and centralization configurations and provides application engineers the opportunity to understand different scenarios while optimizing key parameters to achieve top tier results.
Roth, Jim (Talisman Energy Inc) | Reeves, Clinton Jon (Schlumberger) | Johnson, Carl Robert (Schlumberger Oilfield UK Plc Lasalle) | DeBruijn, Gunnar Gerard (Schlumberger) | Bellabarba, Mario (Schlumberger) | Le Roy-Delage, Sylvaine (Schlumberger) | Bulte-Loyer, Helene (Schlumberger)
Abstract Annular fluid or gas migration, resulting in surface hydrocarbon leaks or sustained casing pressure (SCP), is a problem operators face worldwide. With energy demands escalating, it becomes increasingly important to maintain production from existing wells and bring new wells on line without delay. Internal company policies regarding health, safety and environment, along with increased government scrutiny of the petroleum industry, can require wells to be shut-in if leaks or SCP are present. Estimates of the number of leaking wells have varied widely as reporting standards have evolved over time and from country-to-country. In Western Canada, however, there are detailed reports of over 18,000 wells having Surface Casing Vent Flow (SCVF) that in some cases requires them to be shut in and production suspended. From spud-in to abandonment, an oil well is subjected to numerous, repeated events that could compromise zonal isolation. Resulting damage, in the form of cracks in the isolation material or the creation of a microannulus, can allow hydrocarbons to flow to surface or become trapped below the wellhead. This paper will describe a novel zonal isolation material that responds to a loss of hydraulic isolation. If hydrocarbon flows occur within or around the primary cement sheath, the material will seal these flows and re-establish well integrity. The system, which has slurry properties comparable to standard oilfield cements, is designed to be pumped as part of any primary cementing operation on wells drilled with water or oil-based drilling fluids. This material was used in well construction operations for wells drilled in Eastern Alberta, and can be applied to reduce the incidents of SCVF in this area. This ability of this system to eliminate hydrocarbon flows has been confirmed with high-pressure laboratory testing, and it has been successfully field tested in Western Alberta. Introduction As worldwide demand for petroleum continues to increase, operators face the challenges not only of finding new reserves of oil and gas, but also of maximizing the productivity and longevity of the wells that are drilled into existing reservoirs. According to the International Energy Agency (Oil Market Report 2007; Press Release 2006), worldwide petroleum demand is expected to increase by 13.9 million BOPD, from the current level of 85.9 million BOPD to 99.5 million BOPD, over the next seven years. By contrast, production has increased by only 6.7 million BOPD over the last seven years (Short-Term Energy Outlook 2007). If the industry is to keep pace with this demand, operators will have to look at ways to maximize returns from individual wells, in addition to improving overall reservoir recovery. Great advances have been made in cementing practices over the years. These advances include improvements in fluid displacement modeling as well as the development of slurries with improved chemical and rheological properties. These advances have gone a long way towards improving hydraulic isolation, but they do not address damage to the cement sheath that may occur days, months or years after the cement has set. This potential for loss of hydraulic isolation during or after a well's productive life represents a weak link in hydraulic isolation. A damaged cement sheath can allow the migration of hydrocarbons, which can reach the wellhead in the form of sustained casing pressure (SCP) or surface casing vent flows (SCVF), potentially requiring a well to be shut-in, repaired or abandoned prior to the end of its productive life.
Abstract This paper documents recent field cases in which attempts were made to mitigate casing vent flows (CVF's) on producing and abandoned wells by incorporating permeability-blocking gels with specialized cement blends. CVF's are defined in this paper as sustained gas pressure on the annuli of producing and surface casings. The amount of gas flow rate can vary from a few bubbles to cubic meters per day. However, when the annuli are shut-in, the gas pressure can build to a significant amount. The procedures detailed in this paper are the result of lab studies and postjob reviews of failed remedial attempts. Specific attention is given to why squeeze-cementing procedures can fail to provide long-term seals against source-gas production from casing vents. In most cases, rework of the abandonment procedures cost the operators over $200,000 CAD. The studies showed four possible causes of recurring CVF's:Development of thaumasite in the setting cement Leaking isolation tools Incomplete long-term seal of source zones Incorrect source detection or squeeze interval Cement-source quality and bulk handling methods were also investigated, but showed no evidence of probable cause. This paper explains the findings from laboratory studies and job reviews that lead to improved procedures. These improved solutions were conducted on 23 wells in the later part of 2001. Introduction The industry commonly encounters annular gas pressure on cemented casing annuli. However, this condition is often referred to in different terms based on the local interpretation of the problem. Terms such as sustained annular-casing pressure, annular gas pressure, casing vent flows, or annular gas flows refer to the same general problem. This problem exists when gas pressure builds on casing-by-casing annuli, the pressure is bled to zero, then the gas pressure returns over time. The amount of gas pressure can vary from slightly above atmospheric pressure to that of near deepgas reservoir pressure depending on the gas source and flow path from the source to the surface. Also, the amount of gas bled from the annuli can vary from a very slight flow to 1,000's of standard cubic meters per day. For uniformity in this paper, the described problem of gas pressure in the casing-by-casing annulus will be referred to as casing vent flows (CVF's). CVF's can be caused by several factors. However, the industry has recognized the following factors as the main causes:Poor mud displacement in the primary cement placement (Fig. 1) Cement sheath failure, resulting in sheath cracking (Fig. 2) Gas migration through the setting cement creating gas channels in the set cement (Fig. 3) Low cement top These factors are well documented, appearing frequently in past research. An overview is given in the following sections. Poor Mud Displacement. CVF can also achieve a firm foothold if mud displacement during the primary cementing operations is poor. A primary requisite for lowering the chances of CVF is effective mud displacement, which provides a relatively clean pipe and formation surface to which the cement slurry can bond. Generally, 90% mud displacement efficiency provides adequate zonal isolation, while 95% provides excellent zonal isolation. Lowering the drilled-solids content of the drilling mud, conditioning the hole, and reducing the long-term gel strength of the drilling mud helps obtain more efficient mud displacement. A properly designed cement system does not eliminate the need for proper mud conditioning or for following best cementing practices. These best practices include pipe movement, casing centralization, and spacer design in addition to mud conditioning as stated above. Poor Mud Displacement. CVF can also achieve a firm foothold if mud displacement during the primary cementing operations is poor. A primary requisite for lowering the chances of CVF is effective mud displacement, which provides a relatively clean pipe and formation surface to which the cement slurry can bond. Generally, 90% mud displacement efficiency provides adequate zonal isolation, while 95% provides excellent zonal isolation. Lowering the drilled-solids content of the drilling mud, conditioning the hole, and reducing the long-term gel strength of the drilling mud helps obtain more efficient mud displacement. A properly designed cement system does not eliminate the need for proper mud conditioning or for following best cementing practices. These best practices include pipe movement, casing centralization, and spacer design in addition to mud conditioning as stated above.