The events surrounding the Deepwater Horizon disaster have changed the face of deepwater operations. In order to continue drilling in the Gulf of Mexico, the regulatory body, the Bureau of Safety and Environmental Enforcement (BSEE), has required that applications to conduct work in the Gulf of Mexico (GOM) include a plan to stop, capture, or contain any uncontrolled release of fluids. The capping and containment systems built and implemented by BP during the event are an excellent starting point for minimizing pollution from deepwater subsea blowouts, but the system has limitations. The industry recognizes these limits but is currently focused on meeting the regulatory requirements. This project will analyze events reported to the BSEE in the past 15 years to define the basis for potential capabilities that a capping and containment system should have to minimize the volume of fluid released as well as minimize the time needed to regain control of the well. The analysis will take a detailed look at 90 events over the past 15 years to determine critical factors in the design of a generally applicable capping stack. The research will also look at specific barriers that were used to regain control of the well. Finally, any factors which contributed to the severity of the event or contributed to the success of the blowout response are identified. Based on this detailed review, a list of design considerations for a generally applicable capping stack was created.

The events of the Deepwater Horizon oil spill in the Gulf of Mexico were associated with great water depths that made it difficult to understand the behavior of the spilled oil as it came in contact with the seawater. The remedial subsea application of chemical dispersants draws interest to evaluate the interfacial interactions between the oil and water at such great water depths. Most importantly, a quantification of the interfacial tension (IFT) between the spilled oil and seawater at deepwater conditions can provide insight into the effectiveness of the chemical dispersion of spilled oil. In this study, Macondo crude oil and synthetic seawater samples were used to measure the oil/water IFT by the Pendant Drop method at deepwater conditions of pressure and temperature. A laboratory apparatus capable of representing such conditions was designed and established to enable IFT and density measurements. Reagent grade n-octane was also used to compare its behavior to that of crude oil. The effectiveness of a commercial dispersant, Corexit® 9500, was assessed through the evaluation of the magnitude of the reduction in the hydrocarbon/water IFT. The influence of pressure, temperature, water salinity and dispersant concentration on the IFT was each studied independently as well. The measured oil/water IFT decreased from 25.69 to 22.55 mN/m as both pressure and temperature were changed from water surface to seafloor conditions. The dispersant was capable of reducing the IFT by 70 % from its original value at the water surface while only a 50 % reduction was observed at seafloor conditions. The low temperature associated with the seafloor was determined as the main factor responsible for deteriorating the dispersant effectiveness as pressure had a relatively smaller effect on the IFT. The dispersant was also observed to perform better when dissolved in the crude oil as compared to the time it was dissolved in the water. However, at 10,000 ppm dispersant-in-oil concentration, the oil adopted the shape of a continuous stream instead of breaking up into small droplets. Accordingly, ultra-low oil/water IFT was not achieved, despite such a high dispersant concentration, indicating ineffective chemical dispersion at seafloor conditions.

Effective zonal isolation during primary cementing is only possible when drilling mud in the annulus is completely displaced with cement, while the spacers aid in this process. During the displacement process the rheological properties of fluids used and the operating conditions control the motion of different fluids interfaces; desired stable interfacial displacement leads to piston like motion. Computational Fluid Dynamics (CFD) tool with the Volume-of-Fluid (VOF) has been validated against experimental and used to conduct numerical experiments in a virtual well model consisting of 50 ft vertical section of 8.765" x 12.5" annulus having initially mud and this mud is swept by one annular volume of spacer followed by one annular volume of cement. The 50 ft section was further divided into five subsections each of length 10 ft and average values of quantities for these sections were used for further analysis. The mud and cement properties were kept constant and the spacer density, viscosity and displacement rate were the only controlling parameters to achieve the piston like displacement. The spacer density and viscosity were varied between water and cement with cement being the heaviest and most viscous fluid. Three Reynolds numbers of 100, 167 and 400 were simulated. Temporal variation of the mud volume fraction was used as an indication for the piston like interfacial displacement. For an ideal piston like interfacial displacement the mud fraction reduces sharply with minimum residual mud volume after the spacer sweeps through. A gradual mud reduction represents fluid fingering and the fluctuations in the mud fraction represent fluid mixing. The best displacement was observed when the spacer had the same density as mud while it has the viscosity similar to water. The displacement process was least effective when the spacer had the density equal to cement for all viscosity ranges. Based on the simulation results, a correlation was developed to find the final placed cement volume fraction in the annulus under similar fluid conditions, the utility of CFD based correlation is also presented. Further development of the correlation for varying spacer volume at other operating conditions may be needed to extend its applicability.

<p> Scale control in oilfield operations is the intervention technique deployed to remove the assemblage of solid deposits from the surface of oil and gas well tubular and associated equipment. Common mineral scales that plague production operations are Barium Sulfate, Strontium Sulfate, Calcium Carbonate, and Iron Sulfide. Some of these scales can be dissolved with acid while others cannot. Barium Sulfate which is common at perforations and downstream of chokes is notorious for its resistance to chemical treatment because of its low acid solubility.</p><p> This study investigates the effect of different chemical inhibitors on Barium Sulfate scale. The tube blocking test is widely used to evaluate the efficiency of these chemical inhibitors. Although the principal method of investigation was the tube blocking apparatus, preliminary analysis and optimization were done using the static bottle test and a scale inhibitor performance prediction software called French Creek. The static bottle test was used as a screening method whereby ionic interaction between anionic, cationic and inhibitor solutions gave a clear difference in turbidity or otherwise. The French Creek interface allowed multiple iterations over a range of operating conditions and treatment options. A tube blocking apparatus was constructed to simulate the buildup of scale deposits in an oil pipeline. The set up was operated at pressure and temperature of 100psi and 90&deg;C respectively. Of all the additives tested, phosphonate based chemical had the lowest minimum inhibitor concentration. </p>

Microannular gas flow in the wellbore is known to be one of the major reasons for Sustained Casing Pressure (SCP). Low success rate (under 50%) of costly remedial cementing operations and increasing difficulty in sealing off problematic areas motivated the industry to look for more practical remediation solutions. Expandable casing technology is one of those new proposed techniques. A bench-scale physical model tested the potential of expandable casing technology for remediation of microannular gas migration. The composite samples with pipe-inside-pipe cemented annulus were designed to simulate a wellbore system including a pre-manufactured microannulus on the inner pipe/cement interface. Multi-rate flow-through tests with nitrogen gas first evaluated the permeability and the size of the pre-manufactured microannulus. The post-expansion flow-through experiments tested the ability of pipe expansion in sealing the microannular gas flow. The effects of expansion on properties and structure of the cement were investigated by microindentation, optical microscopy, thermogravimetric analysis (TGA) and inductively coupled plasma (ICP) mass spectrometry. As observed with optical microscopy, the dissolution of unhydrated clinker grains during expansion is coupled with pore collapse within the cement sheath. Information obtained by microindentation showed that the cement sheath loses the integrity initially after expansion but regains most of the mechanical properties after a period of rehydration. Most important, multi-rate gas flow-through experiments showed that all three expansion ratios of 2%, 4% and 8% were successful in sealing the microannular gas flow. The seal was confirmed immediately and then 24 hours and 60 days after expansion. The findings in this research give solid support to the potential of expandable casing technology for remediation of microannular gas migration. Cement pore water propagation is the most likely driving force behind a successful expansion, one that is not an obstacle in subsurface conditions and also makes an ideal environment for cement rehydration post-expansion. Cement integrity should not be compromised by pipe expansion after certain period of rehydration. Finally, the research showed that expansion technology could be used during all operations in vertical and horizontal wells, whether injection or production wells, to mitigate well leaks caused by gas migration.

Although water coning is well understood, it is difficult to control in field operations resulting in low recovery and large volumes of waste produced water. A solution - proposed here - is a multi-functional well with the in-situ bottom water drainage and injection installations - Downhole Water Loop (DWL). Theoretically, DWL greatly improves well performance (for example, a two-fold increase of DWL wells water drainage rate would increase the critical (water-free) oil rate by 80%). However, DWL has practical limitations that must be quantified for actual well design. The objective of this work is to: (1) find maximum water drainage rate to ensure separation of a small amount of under-drained oil from the drainage water; (2) learn how the small oil contamination would impact water injection and how to set criteria for oily water disposal to the bottom aquifer; and, (3) develop a method for assessing feasibility of DWL for oil reservoirs with bottom-water coning problem. Counter-current oil water separation experiments have been to simulate the flow of oil droplets in the downhole water looping section of DWL wells. From the results, an analytical model calculates the maximum water drainage rate that prevents carry-over of oil by the injection water. Aquifer injectivity decline is described by a mathematical model based on mass balance of oil phase in the injected water by considering the effects of oil droplets capture due combined effect of advection, dispersion and adsorption (ADA model) coupled with the two-phase relative permeability relationship. For comparison, a two-phase flow model based on the Buckley-Leverett theory describes aquifer permeability decline during oily water injection process. The two models are in a good agreement for linear flow and excellent agreement for radial flow. Consequently, the aquifer permeability damage is converted to time-dependent skin factor and injection pressure. A comparison of the injection and fracturing pressure gives an estimate of the well stimulation cycle and a criterion for screening reservoir-aquifer candidate for DWL. In order to assess DWL feasibility, a dimensionless model of movable oil recovery vs. seven scaling groups has been built using the inspectional analysis method and multivariable regression technique. The model is used as a final step in the five-step procedure for finding good reservoir candidates for DWL application. Six real reservoirs were used to demonstrate the procedure with three reservoirs becoming good candidates for DWL technology.

Low salinity and composition effects in improving oil recovery in sandstone reservoirs are known. However, these effects have not been thoroughly studied for the carbonate reservoirs. Because of the lack of the clay minerals in the carbonate rocks, the mechanisms for the improved oil recovery with low salinity, brine composition, and temperature may not be the same as those for sandstones. This experimental study attempts to investigate the effects of low salinity, brine composition, and temperature on wettability and oil recovery in a dolomite reservoir. Also, it is attempted to confirm that wettability alteration is the main mechanism for improvement of oil recovery. The experiments for this study were performed at both ambient and reservoir conditions as well as at a temperature of 250°F using two different techniques, Dual-Drop Dual-Crystal (DDDC) and coreflooding. Water-advancing contact angle was measured using the DDDC technique to characterize reservoir wettability with different salinities including twice, 10, 50 and 100 times diluted brines. Also, the effect of brine composition on wettability was investigated with Yates synthetic brine, Yates synthetic brine without sulfate, and brines containing sulfate in different concentrations. In addition, the effect of temperature on wettability was investigated using DDDC technique. Coreflood experiments were carried out using a dolomite core to determine aging time, to measure the oil recovery, and to confirm whether an optimal salinity brine and an optimal composition of brine obtained contact angle measurments improve the oil recovery compared with Yates synthetic brine. Oil-water relative permeabilities were generated by history matching the oil recovery and pressure drop data obtained from the coreflood experiments. The experimental results showed that the wettability was altered from strongly oil-wet to intermediate-wet by diluting the Yates synthetic brine by about 50 times and increasing the amount of sulfate in Yates synthetic brine from 2.2 g/l to 4.4 g/l. Also, increasing the temperature to 250°F had a significant effect on wettability and changed the wettability from oil-wet to intermediate-wet. Coreflood results confirmed the wettability alteration to intermediate-wet and also demonstrated improvements in oil recovery induced by the optimal salinity and optimal brine composition.

The use of foams can be found abundantly in many applications in a wide range of industries, including oil and gas industry. Although understanding foam flow behavior is crucial for the optimization of such applications, the complex flow behavior of foams has been a major challenge. Recent experimental studies with surfactant foams presented a new way to characterize foam flow characteristics by using two flow regimes: the low-quality regime showing either plug-flow or segregated-flow pattern, and the high-quality regime showing slug-flow pattern. This study consists of three main components: (1) experimental investigation of foam rheology in pipes; (2) building up of a new foam model consistent with lab-measured experimental data; and (3) use of the model in petroleum drilling hydraulics modeling and simulation. The major outcome of this study can be summarized as follows. First (Part 1), by conducting foam flow experiments in pipes, this study shows the concept of two foam-flow regimes is still valid and effective not only with surfactant foams but also with foams in the presence of additives such as polymers and oils. This finding is important because many field applications of foam flow involve some levels of additives. Second (Part 2), this study for the first time presents how to build a foam model which is consistent with two foam-flow regimes evidenced by experimental data. The model requires four model parameters two parameters to capture rheological properties (e.g. consistency index and flow behavior index, if power-law rheology is applied) and two parameters to define the dependence of foam rheology to gas and liquid flow rates in both foam flow regimes. Third and last (Part 3), the significance of this model is verified by implementing it into existing foam drilling hydraulics calculations in a 10,000 ft vertical well in which foams are injected down into the drill pipe, through the drill bit and circulated up to the surface along the annulus. The results show that this new foam model equipped with two flow regimes is advantageous over the conventional foam model especially when foams become dry and unstable in the well, improving the accuracy.

Hydraulic fracturing has been serving as the principal reservoir stimulation technique for decades to improve production capacities of low permeability formations. On the other hand, through core and outcrop studies, advanced logging tools, microseismic fracture mapping and well testing analysis, it has been further revealed that many of the shale gas formations are naturally fractured. The presence of natural fractures and their interactions with hydraulic fractures must be taken into consideration while designing fracturing treatment. Although most natural fractures are cemented by precipitations during diagenesis, they may be reactivated during hydraulic fracturing and serve as weak paths for fluid flow and fracture growth. However, current technologies for evaluating naturally fractured reservoirs are incapable of accurately estimating the distribution and properties of natural fractures. Core and outcrop studies involve significant uncertainties in sampling and modeling of microfractures, and prediction of macrofracture properties based on biased observation might lead to erroneous estimation. Existing numerical modeling approach for naturally fractured reservoirs requires accurate details about natural fractures, which is often difficult or expensive to gather during hydraulic fracturing. Moreover, these numerical modeling usually does not incorporate post-treatment measured data, which could not reflect the actual reservoir characteristics. This research proposes a multi-discipline data integration workflow to estimate the characteristics of natural fracture network based on formation evaluations, microseismic data, treatment history and production history. Least-square modeling is first conducted to find natural fracture gridding systems that result in smaller overall squared error between fracture networks and double couple microseismic events. Forward modeling that incorporates Discrete Fracture Network (DFN) is subsequently used to simulate hydraulic fracturing treatments, and the net pressure responses from simulations and field measurements are quantitatively compared to determine the degree of match of natural fracture networks. Reservoir simulation tools are also used thereafter to simulate the production of hydrocarbon from such naturally fractured reservoirs, and the production history from simulations and the actual well will be compared to further evaluate the fitness of natural fracture realizations. This workflow is able to integrate scientific data from multiple aspects of the reservoir development process, and results from this workflow will provide both geologist and reservoir engineers an innovative assessment tool for evaluating and modeling naturally fractured reservoirs.

Well completion plays a key role in the economically viable production of hydrocarbons from a reservoir. Therefore, it is of high importance for the production engineer to have as many tools available that aid in the successful design of a proper completion scheme, depending on the type of formation rock, reservoir fluid properties and forecasting of production rates. Because well completion jobs are expensive, most of the completed wells are usually expected to produce as much hydrocarbon and as fast as possible, in order to shorten the time of return of the investment. This research study focused on the evaluation of well performance at two common completion schemes: gravel pack and frac pack. Also, the effects of sand production on well productivity and its associated erosive effects on the wellbore, downhole and tubular equipment were also a motivation in considering the inclusion of a decoupled geomechanics models into the study. The geomechanics-hydrodynamics modeling was done using a computational fluid dynamics (CFD) approach to simulate a near-wellbore model, on which diverse physical processes interact simultaneously, such as nonlinear porous media flow (Forchheimer formulation), turbulence kinetic energy dissipation, heterogeneous reservoir rock properties and particles transportation. In addition, this study considered a gas reservoir whose thermodynamic properties were modeled using the Soave-Redlich-Kwong equation of state. In general, this study is divided into: 1. Verification of a CFD simulation results against its corresponding analytical solution. 2. Analysis of well completion performance of each of the proposed completion schemes. 3. Effect of using Darcys law on the prediction of well completion performance. 4. Sand production and erosive damage analysis. The CFD approach used on this research delivered promising results, including pressure and velocity distribution in the near-wellbore model as well as three-dimensional flow patterns and effects of sanding on the wellbore integrity.