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.

Water influx and well completions affect recovery from water-drive gas reservoir. Material balance, aquifer models and well inflow equations are used to examine and predict the pressure depletion, water influx, and production rates of water-drive gas reservoirs. The parameters of these simple, lumped models are estimated from simulation results using response surfaces and experimental designs for eight varying geologic and engineering factors. Eleven simulated responses (including maximum gas rate, aquifer and well constants, and water breakthrough) are analyzed using ANOVA and response models. A sensitivity analysis of aquifer productivity index, gas production factor, and sweep efficiency reveals that permeability is the dominating factor. In contrast to earlier investigations, this study indicates that water-drive gas recovery is often higher for higher permeability water-drive gas reservoirs. The high gas mobility more than offsets the high aquifer mobility. The other seven factors are statistically significant for many responses, but much less important in determining reservoir behavior. The proposed approach combines simple analytic expressions with more complete but difficult-to-use reservoir simulation models. The response models can be used to make quick, accurate predictions of water-drive gas reservoirs that include the effects of changing geologic and engineering variables. These simple, approximate models are appropriate for prospect screening, sensitivity analysis and uncertainty analysis.

Surfactants have been considered for enhanced oil recovery by reduced oil-water interfacial tension. However, these surfactants may enhance oil recovery via wettability alteration as well. This study experimentally determines the influence of surfactant type and concentration on oil recovery, oil-water relative permeabilities and wettability in reservoir rocks. Several coreflood experiments were conducted using Yates reservoir fluids in Berea rocks and two types of surfactants (nonionic and anionic) in varying concentrations. A coreflood simulator was used to calculate oil-water relative permeabilities by history matching recovery and pressure drop measured during the corefloods. These relative permeability variations were interpreted using Craig's rules-of-thumb to characterize wettability alterations induced by the surfactants. The two main mechanisms behind the use of surfactants to enhance oil recovery are (1) reduction in interfacial tension and (2) alteration of wettability. To discern the relative contributions from these two mechanisms on enhanced oil recovery, two series of coreflood experiments have been conducted using a nonionic surfactant in varying concentrations. The first series used decane as the oil phase to quantify the effect of reduction in interfacial tension on oil recovery, while considering wettability effects in the decane-brine-Berea system to be negligible. The second series used Yates crude oil in place of decane to quantify the effects of reduction in interfacial tension as well as wettability alteration on enhanced oil recovery. The same two sets of experiments are then repeated with the anionic surfactant. The comparison of results of these four sets of experiments showed significantly higher oil recoveries for second series of experiments, indicating that the surfactants have altered wettability. The optimum surfactant concentration was found to be 3500 ppm. In three of the four cases studied, oil/water emulsions caused high pressure drops during the flooding experiments, strongly affecting the relative permeability curves. Craig's rules-of-thumb may not be applicable in systems containing emulsions. This study suggests that the development of a mixed-wettability state yields significantly higher oil recoveries observed in Yates crude oil systems. The significant contributions of this study are the quantification of the wettability altering capability of surfactants and the consequent enhancement of oil recovery.

Bit performance in deep shale when using water-based mud is typically poor. This study is part of a larger research project to improve that performance entitled "Automated Rig Controls for Improved Drilling Costs." The objective of the project is diagnosis of changes in drill bit performance to provide a logical basis for automating draw works control, maximizing bit performance, and reducing drilling costs. The specific goal of this study is a means to diagnose bit performance, specifically to identify bit balling and lithology changes, using real-time drilling data. The research began by identifying symptoms relating to specific causes of bit performance changes based on previously published research. Four published and six additional new potential parameters were identified for evaluation. Laboratory data was analyzed from both single cutter and full-scale tests to evaluate which diagnostic measures best indicated the causes of different or changing performance. Five of the diagnostic parameters were selected for further evaluation. An example set of field data was acquired that included both surface records of operational parameters and an electric log of the formations in a 2600 foot interval. Rate of penetration was estimated using Lubinski's method. Three published and two new diagnostic parameters were calculated for the entire interval. The sign, magnitude, and trend of these diagnostic parameters were compared to the changes evident in the data to establish the relationship between each diagnostic parameter, the lithology, and whether the bit was balled or drilling efficiently. As a result, a method for defining baseline values of each parameter, identifying lithology, and determining whether the severity of bit balling is constant, being reduced, or increasing is proposed and demonstrated. This method can potentially provide a basis for operational changes to improve bit performance, to help detect lithology changes, and to delineate bed boundaries more accurately.

Oil and natural gas resources in the deepwater Gulf of Mexico are important for the U.S. economy, but development is limited by high costs. Dual density drilling concepts that result in wellbore pressure gradients similar to the natural subsurface gradients can simplify well designs and reduce costs. Riser dilution may be an economical means of achieving such a system. This system would use a low density fluid to dilute the weighted wellbore fluid and give an intermediate density fluid in the riser. Two key concerns addressed in this study are whether a drilling fluid can be formulated that will suspend solids and transport cuttings after dilution and whether the fluid returning from the riser can be separated into wellbore and dilution fluids for a continuous process. The first concern was addressed by laboratory testing of synthetic-base drilling fluids. The wellbore, riser, and dilution fluids were formulated with the same synthetic fluid to water ratio and liquid phase product concentrations with only the barite concentration, and therefore density, being different. Formulations with good emulsion stability over the maximum density range needed for real deepwater applications were developed. However, appropriate rheologies for the extreme case of 17.0 ppg wellbore fluid and 9.5 ppg riser fluid were not achieved with laboratory muds. Separation testing was conducted to address the second concern using a laboratory centrifuge and hydrocyclones. The laboratory centrifuge demonstrated that practically all barite could be removed from the dilution stream and retained in a wellbore stream, but also that the wellbore stream rheologies were excessively high. Hydrocyclone results implied the need for two stages of separation. The most successful two stage trial gave less contrast in densities than the laboratory centrifuge, but gave better rheologies and emulsion stabilities than either the laboratory fluid or the laboratory centrifuge tests. Also, the rheologies from hydrocyclone testing were only slightly less than the rheology values considered necessary for a working riser dilution system. Both the density contrast and the rheologies were also close to the best centrifuge results published by others working on similar systems.