Annular Pressure Buildup Research Articles

Synergistic Assessment of Sustained Casing Pressure on Oil Well

The current research is based on modeling approach, where the objective is to develop a series of computer codes with the reference of existing pressure bleed-off time mathematical models. The results generated from the model are based on the three parameters: temperature, type of gases filled in annulus and depth of well. These three parameters can affect pressure bleed-off time in well's annulus, with the fixed size of needle valve. Using this model generated from Wolfram Mathematical 8.0, it is enable to notify engineer to receive an early sign of warning if the well is suspected to leakage. Meanwhile, based on the matching process of field data and modeled data, field engineers will be able to aware and determine whether the occurrence of annular pressure is due to thermal induced annular pressure buildup or it is because of leakage in well components. The SCP well will eventually loss in production, caused severe failure in well's integrity.

On a Method of Prediction of the Annular Pressure Buildup in Deepwater Wells for Oil & Gas

On a Method of Prediction of the Annular Pressure Buildup in Deepwater Wells for Oil & Gas

海底仕上げにおけるアニュラープレッシャービルドアップのマネージメント

海底仕上げにおけるアニュラープレッシャービルドアップのマネージメント

Multiwell Thermal Interaction: Predicting Wellbore and Formation Temperatures for Closely Spaced Wells

Summary A method is presented to predict wellbore and formation temperatures for a template of closely spaced wells. Multiwell thermal interaction will alter the wellbore temperatures as well as formation temperatures in the interwell zones and also farther out from the well template. The change in temperature profile relative to a single well can be significant. For producing wells in close proximity, wellbore and formation temperatures will converge to a significantly hotter condition than in the isolated-single-well case. The modeling of wellbore and formation temperatures for closely spaced wells has not been widely examined to date. This problem has been approached only by using theoretical formulations based on simplified assumptions. The current work presents for the first time a methodology based on standard industry tools and models that yield results consistent with field experience. The method employs standard industry thermal/hydraulic-modeling software and a finite-element model (FEM) in a loosely coupled, iterative analysis that assumes steady-state conditions. Other numerical approaches including finite-difference (FD) and boundary-element-method (BEM) techniques are also considered. The far-field thermal-flux behavior of a single well is also considered as an important baseline for comparison. The effect of multiwell thermal interaction is important for closely spaced wells such as offshore platforms or subsea and Arctic developments. A case study is presented for a high-pressure/high-temperature offshore field development. The multiwell disturbance on formation and wellbore temperatures affects well design, facilities planning, and operations. Annular-pressure buildup, wellhead movement, tubular-stress design, cement-slurry design, subsidence/compaction effects, and facilities health and safety issues can all be affected. In some cases, unexpectedly high wellbore temperatures can be catastrophic. If multiwell thermal interaction is not taken into account, then load events such as annular-pressure buildup, wellhead movement, and thermal-induced stresses may be underestimated. For high-rate production wells, the increase in produced-fluid temperatures may be small, but even a small change may be critical. In all cases, the effect on outer wellbore strings/annuli and on the formation is significant. This also impacts the planning of offshore fields to be developed in phases with batch drilling.

Sustaining Production by Managing Annular-Pressure Buildup

Summary Increased tubinghead temperature with increased rate may induce pressure increase in the annuli for the trapped fluid. Managing annular-pressure buildup (APB) for sustaining well deliverability is particularly crucial in subsea wells, where intervention is complicated. Ordinarily, a multistring casing design accommodates anomalous pressure rise from the standpoint of well integrity. However, management of day-to-day operations presents challenges when APB occurs. This study presents mechanistic models for understanding and mitigating APB during production. By preserving mass, momentum, and energy in the wellbore, we developed two approaches involving semisteady-state and transient formulations. The intrinsic idea is to mimic the physical process with minimal input parameters to estimate pressure buildup in the annuli. Our model formulation handles the mechanisms of fluid expansion and fluid influx/efflux quite rigorously. This approach appears to be quite sufficient because we account for most of the cases of APB encountered.

Different Methods To Avoid Annular Pressure Buildup by Appropriate Engineered Sealant and Applying Best Practices (Cementing and Drilling)

Summary Many wells that have been successfully cemented initially are showing annulus pressure buildup because of damaged cement- sheath integrity by post-cementing operations/conditions. This has been a concern by many operators where wellbores may be exposed to severe conditions and/or production regimes over a period of time. Sometimes this problem can be temporarily dealt with by releasing the annulus pressure, if environmental conditions and well type will allow. However, this method of annular gas production relief is not a long-term solution to the problem. In addition, it is not always possible to reduce the annulus pressure by releasing the trapped pressure into the environment on a regular basis, even if all other conditions permit this operation. An engineered cement-slurry system can save the operator from facing this situation by applying a lifetime zonal isolation remedy through the proper cement job design. Gas injection in specific areas in the UAE is performed to help maximize the production from these development fields. This paper will discuss the process of engineering a cementing system for these gas-injection wells and the development of a solution that has successfully protected wellbores in gas-injection areas where high pressures are applied to the wellbore. By treating the cement under defined wellbore conditions and studying the mechanical behavior of the cement sheath, it was possible to design a cement- slurry system that could withstand the high pressures applied through gas-injection operations. The mechanical behavior was evaluated using 3D finite element analysis (FEA) that considers mechanical properties such as Young's modulus, Poisson's ratio, and tensile strength in addition to confined compressive strength. The importance of complete zonal isolation is of high order. Elastic cement designs have provided a resilient nonfoamed, or conventional, system that successfully isolated the wellbores for more than a dozen gas-injection wells.

Trapped-Annular-Pressure Mitigation: Spacer Fluid That Shrinks - Update

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112872, "Trapped Annular Pressure Mitigation: A Spacer Fluid That Shrinks - Update," by B. Bloys, SPE, M. Gonzalez, SPE, J. Lofton, R. Carpenter, SPE, S. Azar, SPE, D. Williams, J. McKenzie, SPE, and J. Capo, SPE, Chevron; R. Hermes, Los Alamos National Laboratory; R. Bland, SPE, R. Foley, SPE, and F. Harvey, SPE, Baker Hughes; J. Daniel, F. Billings, and I. Robinson, Lucite International; and M. Allison, Flow Process Technologies, originally prepared for the 2008 SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed. In subsea-completed wells, fluids commonly are trapped in casing annuli above the top of cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced fluids, thermal expansion can create very high pressures and cause the collapse of casing and tubing strings. A successful field trial has been conducted in a 9,800-ft-deep gas well of a water-based spacer fluid that upon heat-triggered polymerization shrinks 20%, mitigating trapped annular pressure (TAP). Introduction TAP, also called annular-pressure buildup, is caused by the thermal expansion of fluids trapped in casing annuli between the top of cement and the wellhead. The pressure buildup usually is a result of heat transfer from produced fluids or from hot drilling fluids circulated while drilling a high-pressure/high-temperature well The pressure can exceed the collapse strength of the casing and production tubing. In land wells, the pressure is relieved easily by bleeding off some fluid through a casinghead valve. In subsea-completed wells, wellheads are much less accessible and generally not fitted with the necessary valves. Perhaps the most successful mitigation approach has been the use of vacuum-insulated tubing (VIT). This technique generally has been successful in keeping the annular-fluid temperatures within an acceptable range. However, with the advent of deeper and hotter wells in deep water, the limits of the protection provided by VIT are being approached in two ways. First, deeper wells have much higher hanging weights that are reaching the stress limits of VIT designs. Second, the greater depths also are producing higher temperatures. Even with the insulating effects of VIT, the temperatures are sufficiently high that pressures are predicted to increase to unacceptable levels. A new approach created a water-based spacer fluid to be used just ahead of the cement. The spacer contains 10 to 30% emulsified liquid methyl methacrylate (MMA) monomer. The liquid MMA shrinks 20 vol% upon polymerizing. The polymerization is triggered by heat and an appropriate chemical initiator. MMA is emulsified into a simple water-based fluid that is intended to be the last spacer pumped just ahead of cement, filling most of the open annulus. The monomer has a low flash point similar to methanol, and it must be handled carefully but has a long record of safe industrial use.

Trapped Annular Pressure: A Spacer Fluid That Shrinks

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 104698, "Trapped Annular Pressure - A Spacer Fluid That Shrinks," by B. Bloys, SPE, and M. Gonzalez, SPE, Chevron; R. Hermes, Los Alamos Natl. Laboratory; R. Bland, R. Foley, SPE, and R. Tijerina, Baker Hughes Drilling Fluids; J. Davis and T. Cassel, Baker Oil Tools; J. Daniel, I. Robinson, and F. Billings, Lucite Intl.; and R. Eley, ICI, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February. The paper has not been peer reviewed. In subsea-completed wells, fluids commonly are trapped in casing annuli above the top of cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced oil and gas, thermal expansion can create very high pressures and cause the collapse of casing and tubing strings. A successful midscale field trial has been conducted in a 500-ft test well to gauge the ability of a liquid monomer that shrinks 20% upon experiencing heat-triggered polymerization to mitigate trapped annular pressure (TAP). A method was devised to add the initiator on the fly as the spacer is pumped downhole. Introduction TAP, also called annular-pressure buildup, is caused by the thermal expansion of fluids trapped in casing annuli between the top of cement and the wellhead. The pressure buildup usually is a result of heat transfer from the produced fluids or from hot drilling fluids circulated while drilling a high-pressure/high-temperature (HP/HT) well. The pressure can exceed the collapse strength of the casing and production tubing. In land wells, the pressure is relieved easily by bleeding off some fluid through a casinghead valve. In subsea-completed wells, wellheads are much less accessible and generally not fitted with the necessary valves. One of the best-documented cases involved the Marlin field, where the production casing and tubing of the first production well collapsed after only a few days of production. A wide range of mitigation techniques has been used, including vacuum-insulated tubing (VIT), leaving the previous casing shoe uncemented, burst disks in casing, nitrogen-based spacers, and crushable urethane foam. Perhaps the most successful mitigation approach has been use of VIT. This technique generally has been successful in keeping the annular-fluid temperatures within an acceptable range. However, with the advent of deeper and hotter wells in deep water, the limits of the protection provided by VIT are being approached in two ways. First, deeper wells have much higher hanging weights that are reaching the stress limits of VIT designs. Second, the greater depths also are producing at higher temperatures. Even with the insulating effects of VIT, temperatures are sufficiently high that pressures are predicted to increase to dangerous levels.

Application of Vacuum–Insulated Tubing to Mitigate Annular Pressure Buildup

Summary Vacuum-insulated tubing (VIT) has been used successfully to mitigate the potentially harmful effects of annular pressure buildup (APB). In a recent deepwater installation, the subject well had lost alternate APB mitigation capability through a series of events. VIT was then chosen as the only viable technology. A common design companion of VIT is gelled brine, chosen to decrease annular natural convection driven by heat loss around the VIT connections. There are, however, several drawbacks to the indiscriminate use of gelled brine: Tight clearances around the tubing hanger running tool, creating the potential for debris plugging and/or tool-recovery issues from the subsea wellhead. Limitations imposed by VIT collapse and hydrostatic packer setting pressures. Unknown temperature/viscosity response and associated quality-control requirements for displacement through a subsea wellhead. A need to reduce operational time and cost. These issues led to the consideration of alternative means of controlling natural convection, and an effort was made to understand, improve, and deploy external coupling insulators. An in-ground vertical experiment with two connected joints of VIT was conducted with and without coupling insulators. Temperatures were monitored at multiple locations. Test results confirm the effectiveness of external coupling insulators. Several theoretical models using different numerical techniques (finite difference, lumped mass/resistance, finite element, and computational fluid dynamics) were found to be consistent with experimental results. These were compared with critical APB temperatures calculated with a commercial wellbore simulator. The net result of these studies was to adopt the external insulators. This paper reviews the experimental data and presents several models of a vertically aligned VIT in a deepwater completion. A comparison of thermally effective APB solutions is presented, together with a critical assessment of modeling and experimental accuracy.

Transient Behavior of Annular Pressure Build-up in HP/HT Wells

Summary Pressure buildup, caused by fluid thermal expansion in sealed annuli of high-presure/high-temperature (HP/HT) wells, can have serious consequences such as casing failure or tubing collapse. To determine whether mitigation was required for a HP/HT development, annular pressures in an appraisal well were studied with a dedicated field test, which consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well, and testing the well several times during a 3-month period, after which the gauge was retrieved, and the data were read out. First of all, comparison of the magnitude of the observed annular pressures with the burst and collapse ratings of the casings shows that annular pressure buildup is a serious consideration in casing design. Such design is to be based on theoretical models for annular pressure buildup. The data acquired with the test serve to validate these models. The data demonstrate that, in general, the theoretical models overpredicted pressure buildup in the annulus. This overprediction was more pronounced at higher temperatures (and pressures) than at lower temperatures, which could not be explained by mechanical factors such as casing ballooning. The influence of these factors was quantified by analyzing the transient pressure response of the annulus. Neither could permanent leakoff of completion fluids explain the discrepancy between theory and test. Leakoff of the annular fluids, which was seen to dominate pressure development during a previous test in a well with a cement shortfall between casings, does not play a significant role in this fully cemented and sealed annulus. This left (1) the properties of the completion fluids differing from the properties of the base fluid (water), and (2) temporary leakoff to near-wellbore fracture systems through the microannuli between cement sheaths and casings as explanations for the observed overprediction. Therefore, estimates on the basis of pure water properties, considering the annulus to be a perfectly pressure-tight vessel, can be considered a worst-case estimate for pressure buildup and a safe basis for design.

Analysis of an Annular Pressure Buildup Failure During Drill Ahead

Summary While drilling ahead in salt on the Pompano A-31 (Gulf of Mexico) wellbore below the 16-in. shoe, the rotary stalled abruptly, and the drillpipe simultaneously became stuck. Subsequent calipers indicated the 16-in. casing to be deformed onto the drillpipe at approximately 250 ft. To the authors' knowledge, this situation represents the first instance of an annular pressure buildup (APB) failure during drilling. APB is typically associated with extremes of temperature change resulting from production operations. In the current instance, the temperature change is solely from circulating drilling fluid. This paper provides a detailed post-analysis of the 16-in. casing failure as follows: An overview of the conventional casing design for this well, indicating that normal operating conditions should not have resulted in a failure. A review of the failure event, substantiated by field measurement and photographs. An investigation of APB, associated with inadvertently closing the 16-in. casing annulus at the surface, demonstrating the magnitude of the possible resulting thermally induced pressure load. Consideration of an alternate failure mode, column buckling, to demonstrate that this failure mode was not active in this wellbore. A finite-element model of the drillpipe/16-in. casing/20-in. casing trio indicating that, in addition to the collapse of the 16-in. casing and subsequent sticking of the drillstring, the outer 20-in. casing was also damaged by the event. The latter item is particularly important because damage to outer strings can be easily overlooked if concentration is on the collapsed casing and drillpipe fish. A mechanical caliper confirms damage to the outer 20-in. string. Conclusions in the paper center on confirmation of the postulated failure mode by field measurement and recommendations for avoiding such an event.

Overview: Well Intervention and Control (January 2006)

This year, we have witnessed the continuation of a general upward trend in the worldwide rig count that started in the second quarter of 2002. The Baker Hughes U.S. rig count published 11 November 2005 stood at 1,479. In the U.S. alone, this increase translates into at least 12,500 people being hired to work on the approximately 750 rigs put to work in the last 3 years. Almost 4,000 of those people were hired to man the 228 rigs placed in operation during the last year alone. One must wonder what effect this growth has on the number of well-control situations encountered. The first line of defense against well-control events is a knowledgeable rig crew—not just the tool pusher and driller, but each person on the crew. Inexperience shows up in different forms at various levels. There have been many cases in which routine kicks were allowed to escalate into critical situations because someone did not report what should have been an obvious sign of the well flowing. An example: an inexperienced floor hand sees flow over the shale shaker with the pumps off but is not aware of the significance. The upper-level positions of the rig crew and the drilling supervisor are expected to have the knowledge and experience to deal with influxes effectively when they occur. Inexperience at this level often results in kicks being taken that should have been avoided and routine kicks being allowed to escalate because of improper handling. Inadequate circulation before pulling out of the hole and improper implementation of kick-circulation procedures are often-cited examples that result in these situations. Keeping experienced personnel on the rigsite during a sustained upswing, such as the one we have experienced over the last few years, is a monumental task. Fortunately, there seems to be an increased awareness of the importance of this experience compared with the last "boom" cycle. This awareness can be seen in the additional focus on rig-crew training and other structured programs designed to minimize well-control incidents. Consequently, the number of serious well-control events is, at least for now, well below the proportionate increase in the rig fleet. Operators and drilling contractors that are driving these efforts should be commended. Well Intervention and Control additional reading available at the SPE eLibrary: www.spe.org SPE 92626 "Modeling Ultradeepwater Blowouts and Dynamic Kills and the Resulting Blowout-Control Best-Practices Recommendations," by Samuel F. Noynaert, SPE, BP, et al. SPE 93956 "High-Pressure/High-Temperature Coiled-Tubing Intervention Operations in the North Sea Within the Past 2 Years," by A. Turner, SPE, Halliburton, et al. SPE 92594 "Development of a Screening System To Identify Deepwater Wells at Risk for Annular-Pressure Buildup," by U.B. Sathuvalli, SPE, Blade Energy Partners, et al.

Transient Behavior of Annular-Pressure Buildup in HP/HT Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 88735, "Transient Behavior of Annular-Pressure Buildup in HP/HT Wells," by P. Oudeman, SPE, and M. Kerem, SPE, Shell Intl. E&P, prepared for the 2004 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 10-13 October. Pressure buildup resulting from the thermal expansion of fluid in the sealed annuli of high-pressure/high-temperature (HP/HT) wells can have serious consequences such as casing failure or tubing collapse. To determine if mitigation was required for an HP/HT development, annular pressures in an appraisal well were studied with a dedicated field test that consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well and testing the well several times during a 3-month period. Introduction Pressure buildup in tubing/casing or casing/casing annuli is usually undesirable. Although casing design should consider high pressures at the casinghead that could result from leakage or thermal expansion of annular fluids, high pressure differences always present the risk of casing burst or collapse at weak points. Most operating companies have some form of annular-pressure management for onshore and platform wells that calls for bleeding off pressure through the wellhead once a predetermined pressure is reached. Such schemes cannot be used in subsea wells because these wells usually will not be equipped with the option to bleed off the annular pressure and to divert the released liquids. In HP/HT wells, the high temperature in the well during prolonged production periods aggravates pressure buildup in the annuli because the thermal expansion of liquids tends to increase at higher temperatures. Because casing-string design must consider those pressures, accurate prediction of annular-pressure buildup is important. Theoretical models to predict thermal annular-pressure buildup have been proposed by a number of authors. Usually, these models take into account fluid thermal expansion, ballooning and compression of the casings, annular fluid leakoff, and formation fluid influx. In a first attempt to validate the theoretical models, a field test was set up to study pressure development in the casing/casing annulus of an offshore platform well. However, in this particular well, the inner (production) casing was not cemented into the shoe of the outer casing. The test demonstrated that in this case, annular-fluid leakoff completely dominated the pressure buildup. The test did not allow any conclusion to be drawn about the overall validity of the theoretical models for pressure buildup. Hence, a second test in the sealed annulus of an offshore HP/HT gas well was planned and executed.

Practical and Successful Prevention of Annular Pressure Buildup on the Marlin Project

SummaryIn late 1999, BP plc experienced a well failure in the Marlin development in deepwater Gulf of Mexico. Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli because of production thermal effects was identified as the most likely cause of the failure.

Field Trial Results of Annular Pressure Behavior in a High-Pressure/High-Temperature Well

Abstract The problem of annular pressure buildup due to heating of the strings by the (hot) well effluent, will typically be of concern in the design of casing strings for high-pressure/high-temperature (HP/HT) sub-sea wells. In such completions bleeding off the pressure through the wellhead, as done routinely with surface wells, is not possible. Theoretical studies indicated that, potentially, extreme pressures could develop in confined sealed annuli of subsea completions, posing a severe threat to well integrity. To investigate the effect under realistic conditions, Shell Expro (UK) ran battery operated gauges in the 9 5/8 in. × 13 5/8 in. annulus of an offshore HP/HT well, to record pressure and temperature changes during drilling, cementing and production testing. This paper presents the results of these tests and a general model for pressure buildup in unconfined sealed annuli to correlate the field data. Since only pressure and temperature measurements were available certain assumptions had to be made with respect to, e.g., formation response to pressure buildup, in situ liquid properties, etc. Although these assumptions could be debatable, it is hoped that by publishing and sharing ideas, a better understanding of annular pressure behavior can be developed.

Casing Design for Trapped Annular Pressure Buildup

Summary Conventional single-string analysis for casing design with annular-fluid expansion can underpredict or overpredict pressures between strings because multistring effects are neglected. Multiple-string systems with multiple sealed annuii behave as composite interactive systems. This paper presents a constitutive-based multistring analysis method for composite string effects and complex fluid behavior. The composite stiffness of cemented casings is determined from elastic stress/strain relationships, and the nonlinear fluid behavior is modeled by direct use of fluid PVT relations in the formulation and solution. The method is incorporated in a computer model linking comprehensive stress calculations to accurate temperature and pressure predictions. Sensitivity studies of the system response to various key parameters and operating conditions are presented, and comparisons are made with single-string analyses to demonstrate the strong interaction between casing strings.