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Abstract One of the critical conditions in cementing operations of gas wells, is the underbalance that generates the entry of preflush in the annular space, especially with the use of in the fluid train, therefore, trying to ensure the pore Pressure control incorporating to the fluid system, only an extensive volume of Spacer. In this way a possible gas inflow is avoided that would lead to enormous economic losses, however in terms of a good removal, just having a spacer in the preflush system would only be Fulfilling a single function that is the drag of suspended solids. in the annular space without being able to disperse and reduce its solid structures. Our methodology has been proven in fields with high GOR and good petrophysical and reservoir conditions, which intend to add a volume of washes to the preflush system, thus Hydrostatic Balance with a low Rheological Spacer volume behind the mud. The preflush system is by batch and pumped at 4.0 bpm continuous, considering a volume of 20 barrel máximum to generate a contact time greater than five minutes, thus improving the conditions of removal, diluting, dispersing and moisturizing the wellbore and casing external. It evaluates Primary cement Using bond logs that was run three days after the cementing operation. The logging results indicate an average amplitude of around 5 mV, so the 5 ½" in. Casing cement job had 90% average bond index. Good zonal isolation was achieved. In addition, Mechanical factors such as reciprocating the casing once carried to Depth, and casing centralization with Standoff greater than 80%, guarantee zonal Isolation in the área of productive. The addition of a Surfactant to the formulation of the washes favors the water wettability of the wellbore in fron of cement. The use of surfactants in preflushes entrain invading gas downhole and créate a stable foam. This foam then presents significant resistance to flow, thereby limiting upward migration (Marrast et al, 1975). With regard to the properties of grouts dominate the rheologic behavior, with filtrations less than 50 cc /30 min, and compressive strength greater than 1,100 psi
Johnson, Carl (Schlumberger) | Gai, Alessio (Schlumberger) | Ioan, Tiberiu (Schlumberger) | Landa, Julian (Schlumberger) | Gervasi, Giuseppe (Ital Gas Storage S.p.A.) | Bourgeois, Benjamin (Geostock) | Bouteldja, Mohammed (Geostock)
Abstract With today's low energy prices and with the increasing drive towards sustainability, it is essential to develop more economically efficient and ecofriendly technologies in oil and gas field development. Such a technology is self-healing cement, which was successfully applied in a large project in northern Italy in the conversion of a gas field to a gas storage field. During the construction phase of gas production and storage wells, one of the critical goals is to achieve competent hydraulic isolation between the surface and the casing to reach the reservoir. There are several cases documented in the literature where poor isolation has resulted in gas flow to surface, thereby polluting water reserves, greenbelts, and populated areas. Improper isolation can also result in interzonal communication, production of unwanted fluids, gas migration, casing corrosion, and sustained casing pressure. These can have significant health, environmental, and economic impact. Additionally, the impending need for well intervention, along with high re-entry costs, will further weaken revenue margins. Breaking through conventional cementing solutions, a global oilfield service company had established an active cement technology to improve annular isolation in gas wells. This technology is capable of self-healing when exposed to hydrocarbons of any type, unlike other self-healing systems that are limited by the level of methane (CH4) in the gas reservoir. The new system allows universal coverage for any concentration of CH4. Because the concentration of CH4 in different gas reservoirs can vary significantly, the self-healing "protection" against different levels of CH4 is tailored to suit different reservoirs. This field-proven technology, in use for more than 10 years, stemmed from the original self-healing technology commercialized more than a decade ago. Subsequently, an opportunity arose to apply this technology in a large project in the north of Italy. The project would exploit a depleted gas field by conversion to a gas storage field with the drilling of 14 wells from two clusters above the reservoir. The product testing and implementation, job execution, and results evaluation brought several benefits with positive impact to the service company and the owner/operator of the field. A higher level of isolation significantly decreases the need for future well integrity and repair, which provides medium- to long-term benefit for the operator—an added value that is sometimes omitted in well construction design. Using a zonal isolation technology, such as the self-healing cement system described here, inherently places the service company and operator in a much more secure position for the future. Furthermore, in the current industry climate, saving 30 to 40 days of rig time and the cost of remedial operations and achieving important mitigation against health and environmental impact pose a significant economic advantage.
Abstract A lightweight cement solution was successfully applied in deepwater wells at depths greater than 1000 m and in production liners terminating in depleted reservoirs. These wells were drilled off the east coast of India. The fracture gradient prognosis for the depleted zones ranged from 11.0 to 11.28 lbm/gal. The measured depth (MD) of these wells was more than 4500 m (MDRT). Mud weights ranged from 10.9 to 11 lbm/gal in the well while drilling the zone. The length of the liner normally ranged from 1400 to 2300 m. The cement slurry was finalized after conducting numerous tests in the laboratory. A lead and tail combination was used for the job to maintain the required equivalent circulating density (ECD). In openhole completions, the casing or liner before the gravel pack should be landed in sand to establish having reached the reservoir top and to help ensure that no shale is present. Challenges for a successful liner job in these wells include landing in a depleted reservoir, which would enable a very low margin between the mud weight and fracture gradient. This margin is further reduced by the minimum horizontal stress mud weight requirement to help ensure that no hole collapse occurs while drilling and before cementing begins. In addition to the depleted zone, to maximize reservoir tapping, the well profiles are highly deviated, often reaching a well deviation of 80+ degrees, resulting in a high ECD during cementing. A long section of the cement column can create problems of cement channeling past the mud and mixing in the annulus. The correct prediction of pore pressure and fracture pressure for different sections is very important. Accurate knowledge of these values is recommended for a correct job design. Some of the lessons learned during the process to help ensure good zonal isolation include the following: An 11-lbm/gal lightweight lead slurry was formulated, keeping ECD and fluid rheology vs. strength development in mind. Solids loading was controlled to help ensure low friction factors (considering rheology) and to achieve a final compressive strength of 2,000 psi because it was a production casing. The length of the tail slurry column was maintained to a minimum to create minimal effect on the ECD, even though the hydrostatic pressure developed was marginal in a highly deviated section. A low-rheology/low-density synthetic oil-based mud (SOBM) (10 lbm/gal) was pumped ahead to reduce the ECD and to maintain the equivalent static density (ESD) above the pore pressure. In addition, the displacement rate was staggered to help maintain the ECDs. A high-viscosity pill was spotted at the 12 1/4-in. section total depth (TD) before the final pullout to act as a base for the cement slurry. This paper highlights the concerns and best practices developed when cementing production liners across depleted formations in deepwater wells.
Li, Zichang (University of Pittsburgh) | Vandenbossche, Julie M. (University of Pittsburgh) | Iannacchione, Anthony T. (University of Pittsburgh) | Brigham, John C. (University of Pittsburgh) | Kutchko, Barbara G. (National Energy Technology Laboratory)
Summary Gases can migrate into the cemented annulus of a wellbore during early gelation when hydrostatic pressure within the cement slurry drops. Different means to describe hydrostatic-pressure reduction have been proposed and reported in the literature. Among them, static gel strength (SGS) is the most widely accepted concept in describing the strength development of hydrating cement. The classic shear-stress theory uses SGS to quantify the hydrostatic-pressure reduction in the cement column. Approaches derived from the concept of SGS have contributed to understanding mechanisms of gas migration and methods of minimizing it. Unfortunately, these approaches do not accurately predict gas migration. Although SGS was originally adopted to describe the shear stress at interfaces, it has also been used to estimate the shear resistance required to deform slurry during the hydration period. Before early gelation, the hydrostatic pressure will overcome the formation gas pressure and prevent gas migrations. During gelation, the cement develops enough rigidity to withstand the gas invasion. This critical hydration period is defined as the transition time. API STD 65-2 (API 2010a) provides standards for determining the transition time by use of the concept of SGS. Current industry practice is to reduce the transition time, thereby lowering the potential for invading gas introducing migration pathways in the cemented annulus. This approach, although certainly helpful in reducing the risk for gas migration, does not eliminate its occurrence. Experimental results presented in this study demonstrate that the relationship between SGS and hydrostatic-pressure reduction is not linear. Characteristics of the transition-time endpoints depend on slurry properties and downhole conditions. Moreover, SGS is not able to characterize the gas-tight property of a cement slurry. When slurry gels, the mechanical properties are governed by its growing solid fraction. The gel can deform under shear loading, but gases and other fluids will need to break or fracture the bond between solids and push them aside for pathways to form within the cement/matrix domain at this point. To fully understand this process, the bond strength between solid particles and the compressibility of the cement matrix are needed. The bond strength and compressibility are mechanical properties dependent on the changing rigidity of the gelling cement. However, SGS does not address these important properties and, therefore, SGS is limited in its ability to predict gas-migration potential. A better means to characterize the cement/matrix strength by use of fundamental concepts and variables for replacing SGS is desired.
Silva, Emilio C. C. M. (Petrobras) | Jandhyala, Siva Rama Krishna (Halliburton) | Bardapurkar, Sameer (Halliburton) | Palla, Venkata Gopala Rao (Halliburton) | Ravi, Kris (Halliburton) | Singh, Sheetal (Halliburton) | Pearl, William (Halliburton)
Abstract Fluid invasion during cement hydration is governed by, among other factors, differential pressure between the formation fluids and the annular fluid. The primary phenomena influencing pressure in the annulus are evolution of cement slurry physical and chemical properties with time, filtrate lost to the formation, and changes in cement slurry volume during hydration. A successful procedure to design slurries to mitigate fluid invasion shall model these phenomena and provide viable methods to measure model parameters. At the same time, it should be feasible to formulate cement slurries to obtain the parameters necessary for a successful design. This paper discusses model details with emphasis on parameters, their test procedures, and equipment details. Dynamic filter-cake properties are calculated by applying compressible filtration theory on data from a modified fluid loss test. Shrinkage/expansion is measured under temperature using the API ring mold apparatus. Pressure and displacement response to filtrate loss and shrinkage/expansion is dependent on bulk modulus, shear modulus, and static gel strength (SGS) evolution of the cement slurry during hydration. Properties are measured as a function of time using sonic analysis and a rotational gel strength device. Both material properties and volume changes attributed to fluid loss and hydration showed time dependency. Furthermore, the pressure response of two realistic wells having different permeability and pore pressure profiles is analyzed. The two analyzed wells had different pressure responses, indicating that the slurry design should be customized for each well. This difference is attributed to varying capabilities of the well to compensate for volume loss by movement of cement placed adjacent to the permeable section, showing that the relative locations of the filtrate loss and potential fluid influx zones are important. Such an observation is possible only because of the ability to measure and model dynamic properties and events. The proposed methods are practical and can be realized using existing equipment with few procedural changes. Analysis based on these measurements guides the customization of slurry designs.
Abstract When cementing liners, the cement must develop compressive strength at the top of the liner before drilling is resumed. Sometimes at high temperature wells, it can take us up to 2 days just waiting for compressive strength development at top of liner conditions. This problem is common when cementing long liners in high temperature wells. An earlier study done by Yami et al. (2007) showed the development of two new retarded systems. The first system is used for non-latex cements for wells that do not show indications of fluid flow. The second cement system includes latex and is recommended for liners with potential for fluid flow. The new retarder systems were effectively applied in a well in Red Sea. This paper discusses the non-latex system field application and summarizes lessons learned. The field application was done by using sodium salt and alicyclic acid with aminated aromatic polymer in combination with sodium salt of organic acid and inorganic salt and aromatic polymer derivatives to cover differential temperature of more than 100 °F.
Abstract Cementing is one of important and crucial issues in oil field especially for high pressure and gas bearing formations. It is difficult to achieve a good zonal isolation in such formation types where pressure is abnormal and formation fluid contains corrosive fluids and gases. A common problem associated with highly over pressurized zones is cross flow after cementing. Fluid flow from an over pressured zone to a low pressure, high permeability zone can lead to deteriorating the existing production hardware. Work over operations that attempt to repair cement voids including perforation, squeezing and use of casing patches or scab liners are not recommended as they do not provide long lasting results. In one of onshore fields in Saudi Arabia there is a persistent problem related to cementing at high pressure zones. Recently, communication between A (abnormally over pressurized zone) and B (low pressure zone) formations is occurring due to long term sea water injection with increasing frequency, and has resulted in production interruption in several wells. This paper addresses the problems through investigating field practices including drilling, cementing, and completion. It also reviews the field reports and cased hole logs. A three-month study was conducted to evaluate the effects of formation-A water on cement, where the cement was exposed to formation-A water under down hole conditions. The tests for permeability, mechanical properties TGA and EDXRF are presented, in addition to discussions of some of the preliminary findings.
Robles, J.. (San Antonio Internacional) | Sapag, F.. (San Antonio Internacional) | Sanchez, L.. (San Antonio Internacional) | Morris, W.. (San Antonio Internacional) | Peacock, H.. (San Antonio Internacional) | Bravo, J.. (UTE Petr?leos Sudamericanos S.A. – NECON S.A.)
Abstract Oil wells with unconsolidated formations where oil and water coexist require special attention during drilling, well completion and production stages. This is the case of a heavy oilfield located in the Neuquina Basin, Argentina, where for many years, periodic cement squeeze jobs were needed to avoid near-wellbore water channeling. In addition to formation unconsolidation, this reservoir has high porosity and permeability as well as poor lithologycal barriers. When the top of the oil producing zone is perforated and evaluated by swabbing, viscous oil carrying formation sand is initially produced. After a short period of time (days), water cut rises to values close to 100 % promoted by the high mobility ratio. This response impedes a profitable production of these oil wells. After analyzing open and cased-hole logs, as well as production history data, the hypothesis for the short term water invasion was identified as near-wellbore channeling caused by sand production. This process was aided by formation weakening due to its interaction with drilling and completion fluids. The solution to this problem was based on a primary cementing procedure that included specially designed slurries containing polymeric admixtures. Effective formation isolation, bonding and near-wellbore consolidation was achieved by allowing these additives to leak-off into the unconsolidated formation. This paper presents the experimental tests performed to develop the procedure and the field results obtained after five successful cementing jobs. Sand production was significantly diminished and no cement repairs were needed after the first six months of production.
Al-Dossary, Abdulla Faleh (King Fahd University of Petroleum and Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum and Minerals) | Hossain, M. Enamul (King Fahd University of Petroleum and Minerals) | Rahman, Muhammad Kalimur (King Fahd University of Petroleum and Minerals) | Jennings, Scott (Saudi Aramco) | Bargawi, Riyadh (Saudi Aramco)
Abstract Cementing is one of the most important and crucial issues in the oil field, especially for high pressure and gas bearing formations. It is difficult to achieve a good zonal isolation in such formation types, where pressure is abnormal and formation fluid contains corrosive fluids and gases. A common problem associated with highly over-pressurized zones is cross-flow after cementing. Fluid flow from an over-pressured zone to a low-pressure, high-permeability zone can lead to deterioration of the existing production hardware. Work over operations that attempt to repair cement voids — including: perforation, squeezing and use of casing patches or scab liners — are not recommended, as they do not provide long-lasting results. In one onshore field in Saudi Arabia, there was a problem related to cementing at high pressure zones. Recently, communication between A (abnormally over-pressurized zone) and B (low-pressure zone) formations occurred due to long term sea water injection, and has resulted in production interruption in a few wells. This paper addresses the problem through investigating field practices, including: drilling, cementing, and completion. This study also reviews the field reports and cased hole logs. A three-month study was conducted to evaluate the effects of formation-A water on cement, where the cement was exposed to formation-A water under downhole conditions. The tests for permeability, mechanical properties TGA and EDXRF are presented, in addition to discussions of some of the preliminary findings.
Summary Microannuli at the well cement-sheath interfaces may result in loss of zonal isolation, which is the source of many problems, such as sustainable annular pressures, crossflows between reservoirs, and undesirable flow behind the casing. The microannuli are commonly explained by variations in cement volume during hydration (chemical shrinkage/expansion) or by contraction of the casing because of a decrease in mud density/temperature because these could create a gap if the cement is unable to follow the induced deformations. However, these two modes are not sufficient to predict all possible types of microannuli encountered in oil and gas wells, meaning that other modes have been missed. This paper presents a comprehensive mechanistic analysis of microannulus formation to highlight and explain other modes and to detail the conditions under which they can appear. It is grounded in both theoretical and experimental evidence and takes into account most of the features that characterize cement after it has been placed, including cement volume variations and heat production during hydration, mud-density and temperature variations, cement thermo-poro-elasto-plastic behavior during and after hydration, thermo-poro-elasto-plastic behavior of the formation, and initial state of stress in the formation.