In this longitudinal study, the authors investigated individual differences in how families adapt to a child's congenital disorder. Family impact, maternal grief resolution, and child attachment were assessed among 74 mothers and their toddlers with a neurological disorder or disfigurement. Fifty dyads were reevaluated 16 months later. For children with neurological compared with disfigurement diagnoses, there was a greater likelihood of negative impact on family, unresolved maternal grief, and insecure attachment at Time 1. Children classified as secure were significantly more likely to have mothers classified as resolved regarding their reactions to their children's diagnosis. Maternal grief resolution was significantly stable (77%) over time and mediated the relation between type of diagnosis and child security. With time, negative impact of child condition on the family decreased and percentage of children classified as secure increased, suggesting that on average families improved. Results suggest that helping parents come to terms emotionally and cognitively with their child's condition may be a useful focus for intervention.

Self-report measures of perceived social support and social undermining consistently have been linked to mental health. Such measures of social relations reflect both shared social reality and respondents' idiosyncratic perceptions, and each of these two components can have different relations to outcomes. This study investigated the extent to which the shared and idiosyncratic components of support and undermining were related to emotion. A clinical sample of 50 adolescents and their family members completed measures of perceived social support and undermining in the family, social desirability, and positive and negative affect. Shared social reality and idiosyncratic perception had different links to emotion depending on the social construct and the emotion. For social undermining, both shared perceptions and adolescents' idiosyncratic perceptions independently predicted negative affect. For perceived support, only adolescents' idiosyncratic perceptions predicted positive affect. Consistent with prior research, support was primarily associated with positive affect, whereas social undermining was primarily related to negative affect.

Within the context of broad industry recognition of two drilling technologies, Underbalanced Drilling predates Managed Pressure Drilling (MPD) by at least a decade. While there are some similarities in some of the equipment and possibly in some of the techniques, the applications are different in their intent. This paper will discuss methodologies comparing Conventional, Underbalanced, and Managed Pressure Drilling Operations with respect to objectives, planning, drilling equipment and operations, and well control. The application of Managed Pressure Drilling was specifically created to give it an identity apart from Conventional Drilling and apart from Underbalanced Drilling. There appears to be some confusion with respect to methodology for Managed Pressure Drilling. What constitutes a Managed Pressure Drilling Operation? What constitutes an Underbalanced Drilling Operation? Are they actually the same? Does it matter? Figure 1 illustrates the general domains of Conventional Drilling Operations, Managed Pressure Drilling Operations, and Underbalanced Drilling Operations. Conventional Drilling Operations Conventional drilling by most accounts had its beginnings at Spindletop, near Beaumont Texas in 1900. Three key technologies contributed to the success of the well and later the drilling industry. They were rotary drive, roller cone bits, and drilling mud. There have been some improvements over the years. Today, the conventional drilling circulation flow path begins in the mud pit, drilling fluid (mud) is pumped downhole through the drill string, through the drill bit, up the annulus, exits the top of the wellbore open to the atmosphere via a bell nipple, then through a flowline to mud-gas separation and solids control equipment, then back to the mud pit. All this is done in an open vessel (wellbore and mud pit) that is open to the atmosphere. Drilling in an open vessel presents a number of difficulties that frustrate every drilling engineer. Conventional wells are most often drilled overbalanced. We can define overbalanced as the condition where the pressure exerted in the wellbore is greater than the pore pressure in any part of the exposed formations. Annular pressure management is primarily controlled by mud density and mud pump flowrates. In the static condition, bottomhole pressure (PBH) is a function of the hydrostatic column's pressure (PHyd) (Figure 2), where… PHyd = PBH In the dynamic condition, when the mud pumps are circulating the hole, PBH is a function of PHyd and annular friction pressure (PAF) (Figure 2), where… PBH = PHyd + PAF In an open-vessel environment, drilling operations are often subjected to kick-stuck-kick-stuck scenarios that significantly contribute to Non-Productive Time (NPT), adding expense for many drilling AFEs. Because the vessel is open, increased flow, not pressure, from the wellbore is often an indicator of an imminent well control incident. Often, the inner bushings are pulled to check for flow. In that short span of time, a tiny influx has the potential to grow into a large volume kick. Pressures cannot be adequately monitored until the well is shut-in and becomes a closed vessel.

Drilling wells in high-pressure, high-temperature (HPHT) reservoirs is often characterized by a narrow operating window between formation pore pressure and fracture pressure. Depletion further reduces this window. Managed Pressure Drilling (MPD) provides methods for operating within safe limits in the narrow HPHT windows. Exceptional control over downhole pressures can be achieved with advanced MPD technologies that are uniquely suited for the HPHT environment. Such control can extend achievable HPHT targets, yet still have the flexibility to deal with the troubles that so often arise in these difficult environments. The advanced MPD system developed for StatoilHydro's Kvitebjørn HPHT field are presented along with experiences from their use in the field. This includes:ManagementRunning a real-time, online, advanced dynamic flow modelAutomatic dual redundant choke system with continuously updated pressure set-point from the flow modelContinuous Circulation System (CCS)Pressure Control While Drilling (PCWD)Caesium Formate mud system - A designer mud containing formation strengthening particles.Balanced Mud Pill (BMP) - An innovative fluid technology developed for performing a precision top kill, producing minimal pressure surge when pulling the drillstring and running liner. Introduction Kvitebjørn is located in the Northern North Sea on the Norwegian Continental Shelf, southeast of the Gullfaks Field (Fig. 1). It is classified as a HPHT gas condensate field. The reservoir consists of sandstones in the Mid-Jurassic Brent group and lower Jurassic (Cook Sst). The top reservoir is at approximately 4,070 m TVD. Early production during development drilling has induced pressure depletion, creating a convergence between pore pressure and fracture pressure in the reservoir. The initial pore pressure was 775 bar (1.93 SG) and fracture pressure was 875 bar (2.19 SG). The reservoir temperature is 155°C and the water depth is 190 m. Nine wells had been drilled into the reservoir prior to introducing the MPD technique. The gas/condensate production started in September 2004 after the second well had been drilled and completed. On the last conventionally drilled well, 34/11-A-2, 140–170 bar of depletion was encountered and massive losses were experienced. Drilling was suspended before reaching TD due to the well-control situation created by these mud losses. The A-2 incident marked the end of the traditional drilling programme as no further drilling on Kvitebjørn would be possible, unless a method could be found to safely operate within Kvitebjørn's reduced "Drilling Window". Prior to drilling the A-2 well, the Kvitebjørn platform produced at maximum capacity, 20.7 MMsm3 gas and 8 Msm3 condensate. After the A-2 incident, the Kvitebjørn production was reduced in an attempt to limit the rate of depletion to complete the primary drilling programme. Production from the field was reduced by 50% in December 2006 and then completely shut down by May 2007 when depletion approached 200 bar.

Shell Exploration and Production successfully deployed an automated bottom hole pressure control system developed by Shell International R&D called Dynamic Annular Pressure Control (DAPC) to solve lost circulation and hole instability problems in a deep water Gulf of Mexico well on the Mars Tension Leg Platform, after two failed sidetrack attempts. Dynamic Annular Pressure Control is a system designed to apply controlled annular surface pressure, with the goal of maintaining constant bottom hole pressure. Bottom hole pressure (BHP) can be maintained at any desired over/under balance by use of a lower mud weight than typical, and adjustment of surface backpressure as the circulation rate is varied. In Shell's maturing deep water developments, rock stress redistribution due to reservoir depletion is causing drilling problems on a scale not seen in the past. High mud weights are still required for hole stability, but reduced fracture gradients have been observed both in reservoir and non-reservoir rock. DAPC was used in the third attempt to sidetrack the Mars A-14 well, to keep Equivalent Circulating Density within the shrinking pore pressure / fracture gradient window. The DAPC system was fabricated, installed and tested on a fast track basis after a review of the technology indicated a high likelihood of enabling the well to be drilled without problems. Cased hole tests indicated that BHP could be maintained within the required limits. The mud weight was reduced for the problematic section, and the well reached planned total depth without experiencing lost circulation or hole instability problems. The production liner was run and cemented without incident. DAPC has been demonstrated as a promising new tool to solve drilling problems associated with reservoir depletion. As the technology matures, it has the potential for broad application to effectively widen the pore pressure / fracture gradient window in deep water, HPHT, extended reach and other challenging drilling environments by continuously and automatically maintaining a desired bottom hole pressure. Introduction The Mars Tension Leg Platform is located in the Gulf of Mexico, approximately 130 miles southeast of New Orleans, in 3,000 feet of water (Figure 1). The A-14 well is an updip oil producer in the waterflooded M1/M2 (Upper and Lower Green) reservoir, and is expected to recover the majority of the reserves. The well was originally drilled and completed in the M2 sand in 1996. The M1 sand was added during a 2000 workover for a sand control failure. A-14 was shut in again in May 2003 because of sand production and decreasing production rate. In 2004 it was decided to redrill the well to the original M1/M2 objective after recovering the slot. The completion tubing and production tie-back were recovered, a whipstock was set, and the well was sidetracked out of the existing 11–7/8″ casing. An intermediate 9–5/8″ × 11–7/8″ expandable liner was successfully set at 14,330' MD. Sidetrack 1 reached total depth of 21,144' (16,340' TVD), at a maximum inclination of 56° and departure of 10,116', when lost circulation was encountered which, in combination with subsequent hole instability problems, led to loss of the bottom hole assembly (BHA). After unsuccessful attempts to fish the BHA, the open hole was plugged back and a second sidetrack was attempted. The plan was to sidetrack from the previous casing shoe, and to set a second expandable drilling liner, in order to be able to run 7–5/8″ production liner across the M1/M2 objective. Hole instability and lost circulation problems prevented the expandable liner from reaching planned depth, and during subsequent remedial operations, a breach was discovered in the 9–5/8″ × 11–7/8″ expandable liner near where the whipstock had been set to exit the 11 ¾″ casing. Well operations were terminated and a detailed After Action Review was carried out.