<p> The limit of drilling ERD comes from the excessive friction between the drill string and borehole. This study investigates the potential of increasing the limit of horizontal displacement through optimization of drilling fluid and bottom hole assemblies. We conclude that lubricating bottom hole with water can significantly increase the maximum permissible WOB. This effect is more pronounced in drilling tight sands than shales with gas. Cooling the bottom hole with gas expansion after bit nozzles can greatly increase the maximum permissible WOB in drilling formations with geothermal temperatures above 200 &deg;C. Three mathematical methods have been developed for calculating the limit of horizontal displacement in extended drilling with gas. The Rigorous Method is recommended because it gives conservative result. Among several factors affecting the ERD with gas, friction coefficient and the weight of pipe in the horizontal section are the two controlling factors. Adequate weight of BHA in the curve section should be used to overcome the friction.</p>

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.

Worlds growing energy demand has pushed oil companies to explore and produce hydrocarbons in complex and technologically challenging deepwater environments. These difficult and complex operations involve the risk of major accidents as well, demonstrated by disasters such as the explosion and fire on the UK production platform Piper Alpha and capsizing of the Deepwater Horizon rig in the Gulf of Mexico (GoM). Accidents cause death, suffering, pollution of the environment, disruption of business and bad reputation to oil industry. A quantitative risk analysis technique has been used in this study to identify and categorize risk associated with different life phases of a deepwater well. Volume of oil released to the environment is used as a risk indicator. Five oil spill scenarios related to drilling and production life phases of a deepwater well are modeled. Risks associated with drilling an exploratory well in the deepwaters of GoM are analyzed in Scenario-1. A representative well location and corresponding reservoir properties were used to estimate the worst case discharge rates (WCD). Fault tree analysis (FTA) was performed to identify and categorize different hazards. Unexpected pore pressure and delayed response to an emergency situation were identified as two most important parameters contributing to overall risk of the system. In Scenario-2 an underground blowout was modeled by using representative geological settings from Popeye-Genesis field. A shallower low pressure zone is exposed to a deeper high pressure zone during drilling. The time to recharge the shallower zone to its fracture pressure is estimated. The shallower zone will transmit hydrocarbons to sea floor once its fracture pressure is reached. Risks associated with production life phase of a deepwater well are modeled in scenario-3. A representative well location and corresponding reservoir properties were used to estimate the WCD. FTA showed that sand screen and subsea tree control failures were main elements contributing to risk. In scenario-4 risk associated with floating production and offloading (FPSO) system for GoM are quantitatively and qualitatively presented. Scenario-5 deals with oil spill risk associated with severe weather conditions. An example mudslide calculation for SP-70 block of GoM is presented.

Modeling subsurface particle transport and retention is important for many processes, including sand production, fines migration, and nanoparticle injection. In this study, a pore-scale particle plugging simulator is concurrently coupled with a streamline reservoir simulator to predict the behavior of particles in the subsurface. The coupled simulators march forward in time together. The automated communication between the two models enables the prediction of spatially and time dependent parameters that control the particle transport process. At each time step, the reservoir simulator provides the inlet velocity and particle concentration of the fluid suspension to the pore-scale model which outputs the permeability, porosity, and retention coefficient. This permits the reservoir simulator to include pore-scale physics at selected locations to determine the number of particles retained and the formation damage. The pore-scale simulator tracks the path of individual particles as they are simultaneously injected into the sample and produces an effluent particle concentration curve that is fit with a continuum-scale advection-dispersion model. The advection-dispersion model is matched to the pore-scale data by adjusting two parameters: the dispersion and retention coefficient. The retention coefficient dictates the number of particles retained across a grid block in the reservoir simulator. Incorporating fundamental pore-scale physics into the streamline reservoir simulator improves its predictive ability by updating the particle retention and formation damage of a grid block at each time step.

The Falkland Islands, located in the SW of the South Atlantic Ocean form the only emergent part of a large continental shelf area, the Falkland Plateau. It has long been known since the work of Adie (1952a,b) that the predominantly Devonian and Permian aged onshore strata probably form the missing SE quadrant of the Karoo Basin of South Africa. Until recently relatively little work has been implemented to confirm this beyond doubt. This study provides additional evidence for such origins through comprehensive sedimentological analysis of onshore Permian exposure in the Falkland Islands with a view to providing a robust stratigraphical framework based on sedimentological data, ichnofacies and petrography. Extensive Falkland Islands fieldwork was complemented by similar work in the Sierras Australes, Buenos Aires Province, Argentina, and in Ecca Pass in South Africa to enable comparisons of the Permian stratigraphy. The Falkland Islands stratigraphic succession represents a post-glacial basin-filling episode representing a passage from a deep underfilled to a filled basin. Deposition occurred within a foreland basin. The results indicate a close correlation between the sedimentology and stratigraphy of South Africa and the Falkland Islands, between which stratigraphic units may be correlated at a member level. The Falkland Islands and South African successions are closely comparable in terms of petrographic trends implying a similar provenance. Strata of the Sierras Australes are sedimentologically and petrographically distinct and deposition of the basin-filling succession at this location commenced at an earlier date. Palaeocurrent orientations between the Falklands Islands and the Sierras Australes succession do not compare well, whilst Falkland Islands palaeocurrent orientations only compare with South African examples if the Falkland Islands are rotated by approximately 180° relative to their present orientation.

A numerous laboratory and field tests revealed that foam can effectively control gas mobility, improve sweep efficiency, and increase oil production, if correctly designed. It is believed that there is a significant gap between small laboratory-scale experiments and large field-scale tests because of two main reasons: (i) typical laboratory flow tests are conducted in linear systems, while field-scale foam EOR processes are performed in radial (or spherical partly) systems in general; and (ii) through the complicated in-situ lamella creation and coalescence mechanisms and non-Newtonian behavior, foam rheology is thought to depend on geometry and dimensionality and, as a result, it is often not clear how to translate laboratory-measured data to field-scale applications. Therefore, this study for the first time investigates how foam rheological properties change in different dimensions and geometries and how such dimensionality-dependent properties are affected by different foam flowing conditions by using mechanistic foam fractional flow analysis. Complex foam characteristics such as three foam states (weak-foam, strong-foam, and intermediate state; sometimes referred to as foam catastrophe theory) and two steady-state strong-foam regimes (high-quality regime and low-quality regime) lie in the heart of this analysis. The calculation results from a small radial or spherical system showed that (i) for strong foams in the low-quality regime injected, foam mobility decreased (or mobility reduction factor increased) significantly with distance which improved sweep efficiency; (ii) for strong foams in the high-quality regime, the situation became more complicated near the well foam mobility decreased, but away from the well foam mobility increased with distance, which eventually gave lower sweep efficiency; and (iii) for weak foams injected, foam mobility increased with distance which lowered sweep efficiency. The results also implied that the use of fixed value of mobility reduction factor, which is common practice in reservoir simulations, might lead to a significant error, especially for strong foams in the low-quality regime. When the method was applied to the large field-scale applications, it was first shown why strong foams would eventually turn into weak foams. Then additional results showed that strong foams could propagate deeper into the reservoir at higher injection rate, higher injection pressure, and at lower injection foam quality. Foam propagation distance was very sensitive to these injection conditions for foams in the high-quality regime, but much less sensitive for foams in the low-quality regime. This study uses a mechanistic foam model similar to Afsharpoor et al. (2010) which is an updated version of Kam and Rossen (2003), Kam et al. (2007), and Kam (2008). In all calculations, gas and liquid phases are assumed to be incompressible and the presence of oil is not considered at this stage.

Reservoir characterization is one of the most important tasks that determines the recovery plan for a specific reservoir. This process incorporates a significant amount of data acquisition and processing to finally develop an acceptable model that matches the production history and can forecast the future production behavior. The model also should be able to adapt to changes along the way: adding or removing producers or injectors, changing the injection pattern, recompletions and converting wells are all examples of possible changes that are common in the oil and gas industry. Usually these changes are modeled by running field-scale simulations and providing the model with the daily data from the field to keep the model up to date and to reduce prediction errors.

<p> Analytical models were derived in this work to predict the Maximum Permissible Pressure (MaxPP) and Minimum Permissible Pressure (MinPP) in CO₂sequestration and other fluid injection wells. The outer radius of the cement sheath should be estimated on the basis of cement placement efficiency measured by the CBL. </p><p> The West Hastings Oil Field and Oyster Bayou Oil Field in Gulf of Mexico region were analyzed to identify the potential leakage of the current CO₂ injection wells using the analytical models. Potential problems for the current wells were identified. There are potential risks for the CO₂ injection wells with relatively smaller wellbore diameter and casing diameter.</p><p> 36 CO₂ injection wells of the West Hastings and Oyster Bayou fields were taken as learning wells to train the neural network model, which was tested by 21 wells in the fields. The results show that the neural network model could be used for predicting the potential likelihood of leakage for CO₂ injection wells, which could be an alternative and convenient way to assess the risk of leakage CO₂.</p><p> Sensitivity analysis was also performed considering cement mechanical properties, well structure and reservoir pressure. Results show that improving cement sheath mechanical properties (cement tensile strength, cement cohesive strength, internal friction angle) is not a very effective means of decreasing potential leakage of CO₂ during CO₂ EOR and carbon sequestration processes. The potential risk of leakage for CO₂ injection wells should be decreased by maximizing the outer radius of the cement sheath and improving the cement placement efficiency. For the current CO₂ EOR activities and carbon sequestration processes, the well head maximum water injection pressure could be increased as the reservoir pressure increases.</p>

Among numerous foam applications in a wide range of disciplines, foam flow in porous media has been spotlighted for improved/enhanced oil recovery processes in petroleum-bearing geological formations and shallow subsurface in-situ NAPL (non-aqueous phase liquid) environmental remediation in contaminated soils and aquifers. In those applications, foams are known to reduce the mobility of gas phase by increasing effective gas viscosity and improve sweep efficiency by mitigating subsurface heterogeneity. This study investigates how surfactant/foam process works fundamentally for environmental remediation purpose by using MoC (Method of Characteristics) based foam modeling and simulation techniques. It consists of two main parts: Part 1, developing foam model using three-phase fractional flow theory accounting for foam flow rheology such as foam strength and stability at different phase saturations; and Part 2, extending the model to investigate the mechanisms of surfactant/foam displacement in multi-layer systems. Part 1 investigates six scenarios such as different levels of foam strength (i.e., gas mobility reduction factors), different initial conditions (i.e., initially oil/water or oil/water/gas present), foam stability affected by water saturation (Sw), oil saturation (So), and both together, and uniform vs. non-uniform initial saturations. The process is analyzed by using ternary diagrams, fractional flow curves, effluent histories, saturation profiles, time-distance diagrams, and pressure and recovery histories. The results show that the three-phase fractional flow analysis presented in this study is robust enough to analyze foam-oil displacements in various conditions, as validated by an in-house numerical simulator built in this study. The use of numerical simulation seems crucial when the foam modeling becomes complicated and faces multiple possible solutions. Part 2 first shows how to interpret theoretically the injection of surfactant preflush and following foams into a single-layer system at pre-specified rock and fluid properties, and then extends the knowledge gained into multi-layer systems where the properties vary in different layers. The results in general show that the mechanisms of foam displacement strongly depend on foam properties such as gas-phase mobility reduction factors (MRF), limiting water saturation (Sw*), critical oil saturation (So*), and so on as well as petrophysical properties of individual layers such as porosity (φ), permeability (k), relative permeability and so on. The overall sweep efficiency in a multi-layer system is very difficult to predict because of the complexity, but the mathematical framework presented in this study is shown to be still reliable. The in-house foam simulator is also extended to compare with modeling results.