A large number of producing wells in the OCS develop undesirable and sometimes potentially dangerous sustained pressure on one or more casing strings of completed wells. This paper examines the severity and frequency of the occurrence of sustained casing pressure in the offshore Gulf of Mexico area. Possible causes for this problem are discussed and case histories of remediation techniques being tried by offshore operators are presented. Introduction The invention of portland cement by Joseph Aspdin has allowed major advances in our civilization because of its low cost, strength, and ability to set under water. It has been modified and used by the oil and gas industry since the early 1900's as the primary means of sealing the area between the open borehole and the casing placed in the well. Shown in Figure 1 is a typical well completion showing the placement of cement to seal off the interior of various casing strings from the subsurface formations exposed by the drill bit. Ideally, the well of Figure 1 should show pressure only on the production tubing. Gauges on all of the casing strings should read zero if:the well is allowed to come to a steady-state flowing condition, andthe effect of any liquid pressurization due to heating of the casing and completion fluids by the produced fluids is allowed to bleed off by opening a needle valve. Only a small volume of fluid generally has to be bled in order for the casing pressure to fall to atmospheric pressure if the pressure was caused by thermal expansion effects. If the needle valve is closed and the well remains at the same steady-state condition, then the casing pressure should remain at zero. If the casing pressure returns when the needle valve is closed, then the casing is said to exhibit sustained casing pressure (SCP). In some cases the pressure can reach dangerously high values. The Minerals Management is concerned about wells on the Outer Continental Shelf (OCS) that exhibit significant sustained casing pressure because of its responsibility for worker safety and environmental protection as mandated by congress. At present, any amount of sustained casing pressure seen on one or more casing strings of a well (excluding drive pipe and structural casing) is viewed as significant enough to trigger notification of MMS. Structural and drive pipe are excluded because it is recognized that gas of biogenic origin is sometimes encountered in the shallow sediments and can cause insignificant pressures on the drive and structural casing. SCP also triggers a requirement that records of the casing pressures observed be kept available for inspection in the operator's field office. Regulations under 30 CFR 250.517 state that the lessee shall immediately notify the MMS District Supervisor if sustained casing pressure is observed on a well. A written record of notification must be placed in the operator's SCP records by close of business the next working day after the SCP is discovered. If the well is felt to be in an unsafe condition, the district supervisor can order that remedial actions be taken. However, provisions are made for a departure from 30 CFR 250.517 to be obtained.

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Accurate prediction of liquid holdup associated with multiphase flow is a critical element in the design and operation of modern production systems. This prediction is made difficult by the complexity of the distribution of the phases and the wide range of fluid properties encountered in production operations. Consequently, the performance of existing correlations is often inadequate in terms of desired accuracy and range of application. This investigation focuses on the development of a neural network model, a relatively new approach that has been successfully applied to a variety of complex engineering problems. Data from five independent studies were used to develop a neural network for predicting liquid holdup in two-phase horizontal flow. A detailed comparison with existing empirical correlations and mechanistic models reveals that the neural network model shows an improvement in overall accuracy and performs more consistently across the range of liquid holdup and flow patterns. Introduction Two-phase flow of gas and liquid in pipes is a near universal occurrence in the petroleum industry. Advancements in subsea completion and multiphase pumping and metering technology have extended multiphase flow over relatively long distances to centralized gathering and separation systems. These developments are becoming increasingly common, especially in remote and hostile locations such as the deepwater Gulf of Mexico. In such cases upfront capital costs are reduced through the consolidation of surface facilities while minimizing flaring and environmental impacts. The design of multiphase production systems requires an accurate estimation of pressure loss.1,2 Liquid holdup, defined as the in-situ liquid volume fraction, is generally the most important parameter in calculating pressure loss. Liquid holdup is also necessary to predict the occurrence of hydrate formation and wax deposition, and to estimate the liquid volume during pigging operations for sizing slug catchers. While pressure losses in single-phase flow in pipes have for a long time been accurately modeled with familiar expressions such as the Bernoulli equation and the Navier-Stokes equations, accurate predictions of pressure loss in two-phase flow has remained somewhat elusive because of added complexities. The lower density and viscosity of the gas phase causes it to flow at a higher velocity relative to the liquid phase, a characteristic known as slippage. Consequently, the associated frictional pressure losses result from shear stresses encountered at the gas-liquid interface as well as along the pipe wall. Additionally, the highly compressible gas phase will expand as the pressure changes along the flow path. Further complicating matters is the variety of physical distributions among the phases. This has led to the common practice of characterizing multiphase flow with flow patterns (Fig. 1). The prevailing flow pattern for a specific set of conditions depends on the relative magnitude of the forces acting on the fluids. Buoyancy, turbulence, inertia, and surface tension forces are greatly affected by the relative flow rates, viscosities, and densities of the fluids as well as the pipe diameter and inclination angle. The complex dynamics of the flow pattern govern effects of slippage and therefore variations liquid holdup and pressure gradient.

The decreasing gap between technology and it's applicability in the oil industry has led to a rapid development of deepwater resources. Beginning with larger fields where the chances of economic success are high, to marginal fields where project economics becomes a more critical parameter, the petroleum industry has come a long way.However, the ever growing water depths and harsher environments being encountered are presently posing challenges to subsea production. Being able to develop a field and then proceeding to ensure flow for the life of the field comprises many situations where the production equipment can fail and falter or through external factors, be deemed unavailable. Some of the areas where most of the current developments in subsea production are being seen are in subsea processing, flow assurance, long term well monitoring and intervention technologies -areas that pose some of the biggest challenges to smooth operation in the deepwater environment.This research highlights the challenges to overcome in subsea production and well systems and details the advances in technology to mitigate those problems. The emphasis for this part of the research is on multiphase pumping, subsea processing, flow assurance, sustained casing pressure problems and well intervention. Someday we'll all sit and have a cup of coffee without wondering how long will it last, because we'll all be together. My parents deserve the hugest mention for standing by me.I loved the mountain bike trails at Lake Bryan where I could get away from it all.vi ACKNOWLEDGMENTS