Wettability is the ability of a fluid to spread or adhere on a rock surface in the presence of other immiscible fluids. Knowledge of wettability is important to decide what production strategy needs to be employed for optimum oil recovery. Wettability is affected by rock mineralogy, rock surface roughness, and brine compositions. Previous studies have dealt with solid-liquid-vapor systems and those involving wettability characterization in solid-liquid-liquid systems have used contact angle techniques known to have reproducibility problems. In this study, a new technique called the Dual-Drop-Dual-Crystal (DDDC) Technique has been used to characterize wettability in terms of dynamic contact angles. The Wilhelmy Plate technique has also been used to measure contact angles for a comparative evaluation of the DDDC results. In studying the effects of surface roughness, brine dilution and surfactant addition in crude oil-brine-rock systems, the Wilhelmy was found to be insensitive, while the DDDC showed significant effects of mineralogy, roughness, brine dilution and surfactant addition on dynamic contact angles. Study of the effects of brine dilution on dynamic contact angles was conducted using Yates brine and its diluted mixtures with deionized water in different proportions. In this study, interfacial tension has been measured using the Drop Shape Analysis (DSA) technique and the results have been compared with those obtained using the du Nuoy ring Tensiometer. A parabolic trend in interfacial tension was observed, with an initial decrease with increasing brine percentage in the mixture and then an increase after attaining a certain minimum. An unxpected effect of oil drop spreading on the rock surface yielding large contact angles was observed for certain brine dilutions. This spreading phenomenon was correlated to the receding angle and interfacial tension as discussed (24,36). A similar effect of oil spreading was also observed when using synthetic brine. This study investigated the effect of a nonionic surfactant on wettability. Initial oil-wet nature of the Yates system was rendered intermediate-wet at certain concentrations of the surfactant. At higher concentrations, the advancing angle decreased to a strongly water-wet angle, indicating the ability of the surfactant to alter the wettability of the crude oil-brine-rock system.

Maintaining underbalanced conditions from the beginning to the end of the drilling process is necessary to guarantee the success of jointed-pipe underbalanced drilling (UBD) operations by avoiding formation damage and potential hazardous drilling problems such as lost circulation and differential sticking. However, maintaining these conditions is an unmet challenge that continues motivating not only research but also technological developments. This research proposes an UBD flow control procedure, which represents an economical method for maintaining continuous underbalanced conditions and, therefore, to increase well productivity by preventing formation damage. It is applicable to wells that can flow without artificial lift and within appropriate safety limits. This flow control procedure is based on the results of a new comprehensive, mechanistic steady state model and on the results of a mechanistic time dependent model, which numerically combines the accurate comprehensive, mechanistic, steady-state model, the conservation equations approximated by finite differences, and a well deliverability model. The new steady state model is validated with both field data and full-scale experimental data. Both steady state and time dependent models implemented in a FORTRAN computer program, were used to simulate drilling and pipe connection operations under reservoir flowing conditions. Actual reservoir and well geometries data from two different fields, in which the UBD technique is being employed, were used as input data to simulate simultaneous adjustments of controllable parameters such as nitrogen and drilling fluid injection flow rates and choke pressure to maintain the bottomhole pressure at a desired value. This value is selected to allow flow from the reservoir to substitute for reduction or cessation of nitrogen injection during drilling and for interruption of nitrogen and drilling fluid circulation during a pipe connection. Finally, a specialized procedure for UBD operations is proposed to maximize the use of natural energy available from the reservoir through the proper manipulation of such controllable parameters based on the results of the computer simulations.

Over 8,000 wells in the Gulf of Mexico exhibit sustained casing pressure (SCP). SCP is defined as any measurable casing pressure that rebuilds after being bled down, attributable to cause(s) other than artificially applied pressures or temperature fluctuations in the well. The Minerals Management Service (MMS) regulations consider SCP hazardous and, in principle, require its elimination. In some cases the agency may allow continuing production at a well with SCP by granting a temporary departure permit. The departure permits are based on diagnostic tests involving pressure bleed-down through a 0.5-inch needle valve followed by closing the valve and recording pressure buildup for 24 hours. Presently, analysis of testing data is mostly qualitative and limited to arbitrary criteria. This work provides theory, mathematical models and software needed for qualitative analysis of SCP tests. SCP occurs due to the loss of wells external integrity causing gas inflow from a high-pressure formation into the wells annulus. Then, the gas migrates upward through a leaking cement sheath, percolates through the mud column and accumulates above the liquid level inside the gas cap. The study identified two scenarios of gas flow in the liquid column: rapid percolation through low-viscosity Newtonian fluid; and, slow ascendance of gas bubble swarms in viscous, non-Newtonian mud. The two scenarios have been mathematically modeled and theoretically studied. The first model assumes rapid percolation and ignores gas entrainment in the liquid column. Simulation showed that early pressure buildup was controlled by mud compressibility, annular conductivity, and gas cap volume while formation pressure controlled the late pressure buildup. Mathematical simulations matched pressure buildups recorded in two wells, showing that the model had physical merit. The second mathematical model fully describes gas migration by coupling the variable rate gas flow in cement with the two-phase flow in liquid column. The model was used to study typical patterns of bleed-down and buildup from SCP diagnostic tests. It showed that analysis of pressure bleed-down gives properties of gas-liquid mixture above the cement, while a sufficiently long pressure buildup may give values of the annular conductivity, the depth and pressure of the gas-source formation.

Underbalanced drilling (UBD) has increased in recent years because of the many advantages associated with it. These include increase in the rate of penetration and reduction of lost circulation and formation damage. Drilling of deviated and horizontal wells also increased since recovery can be improved from a horizontal or a deviated well. The drilling of deviated wells using UBD method will reduce several drilling related problems such as hole cleaning and formation damage. Prediction of flow and pressure profiles while drilling underbalanced in such wells will help in designing and planning of the well. The main aim of this research is to study and model the effect of well deviation on pressure and flow profile in the drillstring and the annulus under UBD conditions through the use of mechanistic two phase flow models. Specifically, a current model is modified to include effects of wellbore deviation. Simulation results are compared with data from a deviated well drilled with UBD technology.

The displacement of oil by gas injection in oil reservoirs is an attractive method of improved oil recovery. Commercial gravity-stable gas injection projects have demonstrated excellent recoveries; however, their application has been limited to dipping reservoirs and pinnacle reefs. Horizontal gas floods and the water alternating gas (WAG) processes, practiced in horizontal type reservoirs, have yielded less than satisfactory recoveries of 5-10%. The Gas Assisted Gravity Drainage (GAGD) Process being developed at LSU extends the concept of gravity-stable gas floods to horizontal type reservoirs to improve volumetric sweep and oil recovery. This experimental study consists of a series of visual experiments to study the effects of operating parameters such as capillary number, the Bond number, gravity number and mobile water saturation on the GAGD process. The experiments were performed in a visual physical model packed with uniform glass beads of various sizes and by injecting gas at various pressures, rates and initial water saturations. The results have been correlated against dimensionless numbers characterizing the role of gravity and capillary forces. This has also enabled the comparison of the physical model results with those from core floods and field projects. The run time of the physical model experiments have been scaled to the required time in the field to obtain similar recoveries. Good correlations are obtained between the Bond and capillary numbers with cumulative oil recovery. Results indicate that these correlations are not only valid for immiscible GAGD floods but may be applicable for miscible GAGD floods. This enables us to predict oil recoveries from similar processes on commercial scale if sufficient rock and fluid data is available. Significantly better oil recovery is obtained during the early life of the project at constant pressure gas injection. Higher recoveries are obtained during gravity-dominated flow as opposed to capillary or viscous dominated. Experimental results show that the composition of the injected gas has little effect on oil recovery during immiscible gas injection. Recovery versus gravity number data from the physical model, core floods and commercial field projects, all fall close to a straight line on a semilog plot. This indicate that the physical model is capable of capturing the realistic mechanisms operating in the field projects and that these experimental runs may be reasonably extrapolated to field scale.

The current methods for off - bottom control of blowouts involve pumping kill fluid into the well through an injection string. These are the dynamic kill and the momentum kill. The dynamic kill, which is based on the steady state system analysis approach, and the momentum kill, that is loosely based on the Newton's Second Law of Motion, have been used extensively in off-bottom control of actual blowouts. A comprehensive study of these two concepts was performed. The review included an analytical analysis of the published design techniques for both of these methods. The application of these techniques to several different field and hypothetical cases were compared. The study drew conclusions about the conceptual validity, applications, advantages, substantial shortcomings, and design problems for each method. In this work, an alternative method for controlling an off - bottom blowout was also developed. The method is based on the dynamic kill and bullheading concepts and is called "dynamic seal - bullheading". Conceptually, the method involves two important stages in the control process. First, a dynamic seal is established at the injection string depth. Second, this forces a portion of the kill fluid to flow downward displacing, equivalent to bullheading, the remaining formation fluid in the wellbore back into an open formation. The models for each stage of this method were implemented in a computer program to give a design method for estimating the kill parameters such as kill flow rate, kill fluid density, kill fluid volume, pumping time and effect of control depth. The program also calculates the formation fluid influx, surface pressure, bottomhole pressure, and pressure at critical points in the well as a function of time during the control. The proposed method and the conventional dynamic control method were compared for two different off - bottom blowout scenarios using the new computer program. The first scenario is an actual field case and the second is a hypothetical blowout with input data from a real well configuration and reservoir. In both cases, dynamic seal - bullheading would provide a more reliable and conclusive kill in a minimum period of time

Water inflow may cease production of gas wells, leaving a significant amount of gas in the reservoir. Conventional technologies of gas well dewatering remove water from inside the wellbore without controlling water at its source. This study addresses mechanisms of water inflow to gas wells and a new completion method to control it. In a vertical oil well, the water cone top is horizontal, but in a gas well, the gas/water interface tends to bend downwards. It could be economically possible to produce gas-water systems without water breakthrough. Non-Darcy flow effect (NDFE), vertical permeability, aquifer size, density of well perforation, and flow behind casing increase water coning/inflow to wells in homogeneous gas reservoirs with bottom water. NDFE is important in low-productivity gas reservoirs with low porosity and permeability. Also, NDFE should be considered in the reservoir (outside the well) to describe properly gas wells performance. A particular pattern of water rate in a gas well with leaking cement is revealed. The pattern might be used to diagnose the leak. The pattern explanation considers cement leak flow hydraulics. Water production depends on leak properties. Advanced methods at parametric experimental design and statistical analysis of regression, variance, with uncertainty (Monte Carlo) were used building economic model at gas wells with bottom water. Completion length optimization reveled that penetrating 80% of the gas zone gets the maximum net present value. The most promising Downhole Water Sink (DWS) installation in gas wells includes dual completion with an isolating packer and gravity gas-water separation at the bottom completion. In comparison to Downhole Gas/Water Separation wells, the DWS wells would recover about the same amount of gas but much sooner. The best DWS completion design should comprise a short top completion penetrating 20% - 40% of the gas zone, a long bottom completion penetrating the remaining gas zone, and vigorous pumping of water at the bottom completion. Being as close as practically possible the two completions are only separated by a packer. DWS should be installed early after water breakthrough.

This thesis will analyze the techniques used during the 1989 and 1990 workover programs as well as subsequent operations in 1991/1992. It will also present the techniques and results of the most recent 1999 workover program undertaken to alleviate the most persistent sustained casing pressure (SCP) in a mature Gulf of Mexico field. An extensive literature review is included to better illustrate the complexity of the issues involved and possible SCP mechanisms. The field was drilled during the 1980s and SCP has been prevalent in some cases previous to initial completion operations. Previous remedial programs resulted in limited success in reducing SCP previous to the most recent workover program beginning in 1999. Critical analysis will be based on a review of the methods used and the results obtained. Knowledge gained from the most recent 1999 workover program will be applied to evaluate the effectiveness of the methods employed. Programs previous to the most recent 1999 workover program were not successful in eliminating SCP since pressure returned almost immediately to the affected casing in most instances. During the programs, perforating or cutting casing to squeeze cement into affected annuli was not successful at any depth. A review of the workover attempts will rely on internal correspondence and drilling reports. These will be compared to the knowledge and results gained from the 1999 rig operations program. The objective of the 1999 workover program was to address SCP in the field with a consistent and effective method. Techniques were developed by analyzing the successes and failures of past operations and applying aggressive remediation programs tailored to individual wellbores. Discussion will include improved design guidelines in hole preparation before milling and cementing operations, improved milling procedures, and application of a latex cement slurry. Even though some remedial rig work was required while operations were still ongoing, all indications are that the 1999 workover program was successful.

This research investigates the feasibility of the dynamic lubrication method of well control as an alternative to conventional stepwise lubrication. The applicability of flooding phenomena to dynamic lubrication and its use in an optimization method to maximize pumping rates was also investigated. An experimental approach was taken in which experiments were conducted in a 13 long laboratory apparatus designed to emulate the geometry in a wellhead and also in a full-scale research well. The laboratory experiments were conducted to visually investigate the mechanism of flooding and derive a flooding correlation applicable to this type of system. The full-scale experiments were done to evaluate the dynamic lubrication method, compare it to conventional lubrication, attempt dynamic lubrication at high pumping rates, assess the applicability of flooding as the rate determining phenomenon, and identify any complications encountered during this process. The laboratory tests produced a correlation that was applicable over a range of 3 annular sizes. The equation resembled correlations from previous studies by Richter (1981) and Dempster(1984) and used dimensionless volumetric fluxes as the non-dimensional parameter. The full-scale tests showed that dynamic lubrication was more efficient in removing gas trapped at the wellhead, and reduced the severity of pressure fluctuations inherent in conventional stepwise lubrication. Pumping at constant high rates had an adverse effect on the process. This high pumping rate reduced the rate of accumulation of liquid in the well by 50% when compared to the more conservative pumping rates. The boundary between efficient and inefficient pump rates corresponded well to the correlation from laboratory tests if the relevant dimensions were assumed to be dependent on wellhead geometry. For this wellhead, the casing-casing annulus has a smaller cross sectional area and therefore higher velocities, which logically should control flooding. However, using the casing annulus geometry in the flooding correlation results in incorrect prediction of the onset of flooding unless revised coefficients are used. These revised coefficients were adopted for a proposed preliminary optimization method.

Drilling operations represent the major cost in finding and developing new petroleum reserves. Poor drilling performance when drilling deep shale and strong rocks, as evidenced by slow rate of penetration (ROP), has a significant detrimental impact on drilling costs. Also, it has been concluded that bit balling is the main cause of low ROP when drilling deep, clay-rich shale with water-based mud. In addition, it is estimated that a potential saving in drilling cost of hundreds of millions of dollars a year can be obtained if bit balling is mitigated and ROP is improved. Several methods have been developed in order to improve bit performance. Recently, Arash Aghassi 1 and John R. Smith 37 proposed one of them, which uses simple drilling data to identify bit balling and lithology change as two separate effects through the calculation of five diagnostic parameters and comparing these values to a baseline zone. The objective of this research is to apply, evaluate, and improve the method proposed by Aghassi and Smith. A set of down-hole well data and several sets of surface well data were used to evaluate the method. The diagnostic parameters of Aghassis method were calculated, first using the down-hole data, and then with surface data. All of the results were correlated with and compared to wire-line logs. As a result, the utility of using surface data was confirmed. The overall utility of the method and its diagnostic parameters for detecting the occurrence of, and increases in, the severity of bit balling as distinguished from drilling into a stronger rock were evaluated. The results were very sensitive to the selection of the baseline; also, when drilling strong rock, the interpretation of the diagnostic parameters is sometimes that the bit is balled. Statistical Logistic Regression models were developed and evaluated as a means to solve these problems. Those models were applied using several sets of well data. As a result, it was determined that the logistic regression can potentially provide a basis for distinguish between bit balling and strong rock. It can be used independently, but it is more effective as a complement to Aghassi & Smiths method.