Thesis (MScEng)--Stellenbosch University, 2011. / ENGLISH ABSTRACT: South Africa is a relatively dry country with an annual average rainfall of 464mm compared to a world average of 860mm (WSA, 2009). Water shortages and droughts are fairly common to the western and high lying of regions South Africa. Due to its population growth and the rapid development, like the rest of the world, there has been an increased demand for water. Due to increasing costs of procuring water and its decreasing availability, the option of using seawater as a source for freshwater or directly in industrial processes has become competitive, especially in the arid parts of the world. The design of seawater intakes forms an integral part of providing a secure source of seawater. The objective of this thesis is to aid in the development of guidelines for the design of small scale seawater abstraction systems on rocky coastlines using the Horizontal Well Method. Recommendations for guidelines will be given. / AFRIKAANSE OPSOMMING: Geen opsomming

Horizontal well temperature and pressure distributions can be measured by production logging or downhole permanent sensors, such as fiber optic distributed temperature sensors (DTS). Correct interpretation of temperature and pressure data can be used to obtain downhole flow conditions, which is key information to control and optimize horizontal well production. However, the fluid flow in the reservoir is often multiphase and complex, which makes temperature and pressure interpretation very difficult. In addition, the continuous measurement provides transient temperature behavior which increases the complexity of the problem. To interpret these measured data correctly, a comprehensive model is required. In this study, an interpretation model is developed to predict flow profile of a horizontal well from downhole temperature and pressure measurement. The model consists of a wellbore model and a reservoir model. The reservoir model can handle transient, multiphase flow and it includes a flow model and a thermal model. The calculation of the reservoir flow model is based on the streamline simulation and the calculation of reservoir thermal model is based on the finite difference method. The reservoir thermal model includes thermal expansion and viscous dissipation heating which can reflect small temperature changes caused by pressure difference. We combine the reservoir model with a horizontal well flow and temperature model as the forward model. Based on this forward model, by making the forward calculated temperature and pressure match the observed data, we can inverse temperature and pressure data to downhole flow rate profiles. Two commonly used inversion methods, Levenberg- Marquardt method and Marcov chain Monte Carlo method, are discussed in the study. Field applications illustrate the feasibility of using this model to interpret the field measured data and assist production optimization. The reservoir model also reveals the relationship between temperature behavior and reservoir permeability characteristic. The measured temperature information can help us to characterize a reservoir when the reservoir modeling is done only with limited information. The transient temperature information can be used in horizontal well optimization by controlling the flow rate until favorite temperature distribution is achieved. With temperature feedback and inflow control valves (ICVs), we developed a procedure of using DTS data to optimize horizontal well performance. The synthetic examples show that this method is useful at a certain level of temperature resolution and data noise.

Horizontal wells have been used to increase reservoir recovery, especially in unconventional reservoirs, and hydraulic fracturing has been applied to further extend the contact with the reservoir to increase the efficiency of development. In the past, many models, analytical or numerical, were developed to describe the flow behavior in horizontal wells with fractures. Source solution is one of the analytical/semi-analytical approaches. To solve fractured well problems, source methods were advanced from point sources to volumetric source, and pressure change inside fractures was considered in the volumetric source method. This study aims at developing a method that can predict horizontal well performance and the model can also be applied to horizontal wells with multiple fractures in complex natural fracture networks. The method solves the problem by superposing a series of slab sources under transient or pseudosteady-state flow conditions. The principle of the method comprises the calculation of semi-analytical response of a rectilinear reservoir with closed outer boundaries. A statistically assigned fracture network is used in the study to represent natural fractures based on the spacing between fractures and fracture geometry. The multiple dominating hydraulic fractures are then added to the natural fracture system to build the physical model of the problem. Each of the hydraulic fractures is connected to the horizontal wellbore, and the natural fractures are connected to the hydraulic fractures through the network description. Each fracture, natural or hydraulically induced, is treated as a series of slab sources. The analytical solution of superposed slab sources provides the base of the approach, and the overall flow from each fracture and the effect between the fractures are modeled by applying superposition principle to all of the fractures. It is assumed that hydraulic fractures are the main fractures that connect with the wellbore and the natural fractures are branching fractures which only connect with the main fractures. The fluid inside of the branch fractures flows into the main fractures, and the fluid of the main fracture from both the reservoir and the branch fractures flows to the wellbore. Predicting well performance in a complex fracture network system is extremely challenged. The statistical nature of natural fracture networks changes the flow characteristic from that of a single linear fracture. Simply using the single fracture model for individual fracture, and then adding the flow from each fracture for the network could introduce significant error. This study provides a semi-analytical approach to estimate well performance in a complex fracture network system.

During injection of a high-viscosity, non-Newtonian polymer into a long horizontal well, a significant pressure drop occurs along the well length. Computational Fluid Dynamics (CFD) modeling of the shear-thinning flow of polymer in the wellbore, coupled with the viscoelastic flow in composite gravel-pack/near-well formation zone, was carried out to develop convenient correlations for axial pressure values of both Newtonian and non-Newtonian fluids along the well length, for use in chemical EOR simulations. The detailed CFD modeling of the non-Newtonian flow behavior of polymer within the horizontal wellbore, completion zone and the near-well formation, not only allows accurate accounting of pressure distribution along the long horizontal well, but also can be employed for screening diagnosis for possible injectivity inefficiencies resulting from non-uniform pressure values. At both high and low injection rates, CFD modeling predicts non-uniform pressure distributions for highly viscous fluids. The inclusive pressure correlation was implemented into UTCHEM, a University of Texas at Austin research simulator, to determine the importance of including pressure drop in polymer injections. Early times (i.e., less than 100 days) yielded a significant oil recovery deviation from a uniform pressure wellbore. However, at later times the recovery loss generated by the pressure decrease was deemed negligible; therefore, the traditional assumption regarding uniform pressure in horizontal wellbores was still reasonable for highly viscous non-Newtonian flow. This CFD study is the first mechanistic investigation of the polymer injectivity with detailed description of the wellbore, completion zone and near-well formation, and with full accounting of the shear-thinning rheology for pipe flow and the viscoelastic rheology of polymer in porous media. With increased use of very high molecular-weight polymers for chemical EOR processes for mobility control, the latter mechanism is known to be critical. / text

This dissertation is composed of three parts of major contributions. In Chapter II, we discuss analytical study of contaminant transport from a finite source in a finite-thickness aquifer. This chapter provides analytical solutions of contaminant transport from one-, two-, and three-dimensional finite sources in a finite-thickness aquifer using Green's function method. A library of unpublished analytical solutions with different finite source geometry is provided. A graphically integrated software CTINT is developed to calculate the temporal integrations in the analytical solutions and obtain the final solutions of concentration. In Chapter III, we obtained solutions of groundwater flow to a finite-diameter horizontal well including wellbore storage and skin effect in a three-dimensionally anisotropic leaky aquifer. These solutions improve previous line source solutions by considering realistic well geometry and offer better description of drawdown near the horizontal well. These solutions are derived on the basis of the separation of the source and the geometric functions. The graphically integrated computer program FINHOW is written to generate type curves of groundwater flow to a finite-diameter horizontal well. The influence of the finite-diameter of the well, the wellbore storage, the skin effect, the leakage parameter, and the aquifer anisotropy is thoroughly analyzed. In Chapter IV, a general theory of groundwater flow to a fractured or non-fractured aquifer considering wellbore storage and skin effect is provided. Solutions for both leaky confined and water table aquifers are provided. The fracture model used in this study is the standard double-porosity model. The storage of the aquitard (the leaky confining layer) is included in the formula. A program denoted FINHOW2 is written to facilitate the calculation. Sensitivity of the solution to the confined versus unconfined conditions, fractured versus non-fractured conditions, and wellbore storage and skin effects is analyzed.

This paper presents modifications to two widely used numerical groundwater flow models in an effort to improve upon the interaction between a well of finite length and conductivity with the surrounding formation. The first objective is to discard the common assumptions about flux- or head-based boundary conditions along the well screen by coupling pipe flow hydraulics and groundwater flow. The second objective is to avoid restricting the wellbore hydraulics to a single flow regime. Five flow regimes (laminar through rough-turbulent), based on Reynolds number and pipe roughness, are considered. The modifications are integrated into the highly versatile, well-documented and well-tested models HydroGeoSphere (finite-element/finite-difference) and USGS MODFLOW (finite-difference). Verification of the algorithm and code and is performed by comparing results to: 1) the idealized, analytical Theis solution; 2) the original, unmodified code; and 3) the results of a third party numerical solution that also accounts for variable frictional wellbore losses. Results highlight the inadequacy of either a uniform flux or a uniform head assumption along the wellbore. The solution also tends to produce much steeper hydraulic gradients in those portions of the aquifer nearest the pump intake than have previously been predicted. Systems most affected by in-well hydraulic losses include those for which well screen is long, pumping rate is large, pipe diameter is small, pipe roughness is large (either through design or aging) and aquifer conductivity is high. Improved modeling of the non-linear hydraulic conditions within the well screen can particularly influence the interpretation of wellbore flowmeter and tracer tests, leading to more precise knowledge of the variation of local aquifer hydraulic conductivity along well screens. Aquifer drawdown curves, solute transport and inflow velocities will also be influenced, which can impact capture zones and remediation costs. Given that the solution is incorporated within the HydroGeoSphere and MODFLOW models, it presents the additional advantage over existing approaches of offering a wide range of modeling capabilities, such as three-dimensional flow, arbitrary well inclination and surface-subsurface flow integration. / Thesis (Master, Civil Engineering) -- Queen's University, 2008-01-04 17:27:50.629

Master of Science / Department of Geology / Matthew W. Totten / The Woodford Shale (Oklahoma, U.S.A.) is a prolific unconventional hydrocarbon resource. The Woodford has been shown to be heterogeneous in many geochemical, mineralogical, and rock mechanic properties across the state of Oklahoma, which presents a challenge to successful exploitation of this resource (Caldwell, 2014; Turner et al., 2015; Wiley, 2015; Zhang et al., 2017). Most prior studies of the Woodford Shale report properties from a single sample collected from a vertical well, which reports these values as a single point source on a distribution map. Studies using outcrop localities report lateral variations in several rock properties of the Woodford, but are limited to the short distances an outcrop provides (Turner et al., 2015). The main focus of this research is to determine whether rock properties important to the productivity of the Woodford Shale vary across a lateral well bore within the Woodford shale. Measurements of chemical and mineralogical compositions were performed on rock cutting samples from a single horizontal well path of the Carleigh 6H-32 across approximately one mile. The mineral makeup was determined by use of X-ray diffraction (XRD) and elemental concentrations were determined by hand-held X-ray fluorescence (HHXRF). What was found is that the Upper and Middle Woodford Shale are relatively homogeneous laterally. The lack of variation means that it’s possible to determine from which subgroup samples may have been taken. The geochemical data were used to calculate a mineral-based brittleness index (Wang and Gale, 2009), which was compared to the measured frack gradient across perforations of the Carleigh 6H-32 well. In addition, the total organic matter content (TOC) was approximated in the same samples using loss on ignition (LOI) methods. The calculated mineralogy within samples assigned to the Middle Woodford show some variability throughout the horizontal well, which leads to an associated variation in mineral brittleness index when using the Wang and Gale (2009) formula. The mineral based brittleness index correlates with observed fracture gradient during well completion. This suggests that the tendency to fracture is also variable along the well path, which should be considered during design of the well completion.

Condensate blockage negatively impacts large natural gas condensate reservoirs all over the world; examples include Arun Field in Indonesia, Karachaganak Field in Kazakhstan, Cupiagua Field in Colombia,Shtokmanovskoye Field in Russian Barents Sea, and North Field in Qatar. The main focus of this thesis is to evaluate condensate blockage problems in the North Field, Qatar, and then propose solutions to increase well productivity in these gas condensate wells. The first step of the study involved gathering North Field reservoir data from previously published papers. A commercial simulator was then used to carry out numerical reservoir simulation of fluid flow in the North Field. Once an accurate model was obtained, the following three solutions to increasing productivity in the North Field are presented; namely wettability alteration, horizontal wells, and reduced Non Darcy flow. Results of this study show that wettability alteration can increase well productivity in the North Field by adding significant value to a single well. Horizontal wells can successfully increase well productivity in the North Field because they have a smaller pressure drawdown (compared to vertical wells). Horizontal wells delay condensate formation, and increase the well productivity index by reducing condensate blockage in the near wellbore region. Non Darcy flow effects were found to be negligible in multilateral wells due to a decrease in fluid velocity. Therefore, drilling multilateral wells decreases gas velocity around the wellbore, decreases Non Darcy flow effects to a negligible level, and increases well productivity in the North Field.

Made available in DSpace on 2014-12-17T14:08:49Z (GMT). No. of bitstreams: 1 CindyPAR_DISSERT.pdf: 3888295 bytes, checksum: 74ba5d896661a5a41c98018b93246cd9 (MD5) Previous issue date: 2012-02-17 / Conselho Nacional de Desenvolvimento Cient?fico e Tecnol?gico / Oil recovery using waterflooding has been until now the worldwide most applied method, specially for light oil recovery, its success is mainly because of the low costs involved and the facilities of the injection process. The Toe- To-Heel Waterflooding TTHWTM method uses a well pattern of vertical injector wells completed at the bottom of the reservoir and horizontal producer wells completed at the top of it. The main producing mechanism is gravitational segregation in short distance. This method has been studied since the early 90?s and it had been applied in Canada with positive results for light heavy oils, nevertheless it hasn?t been used in Brazil yet. In order to verify the applicability of the process in Brazil, a simulation study for light oil was performed using Brazilian northwest reservoirs characteristics. The simulations were fulfilled using the STARS module of the Computer Modelling Group Software, used to perform improved oil recovery studies. The results obtained in this research showed that the TTHWTM well pattern presented a light improvement in terms of recovery factor when compared to the conventional 5- Spot pattern, however, it showed lower results in the economic evaluation / A recupera??o de ?leo com inje??o de ?gua tem sido at? agora o m?todo mais aplicado no mundo inteiro, principalmente para a recupera??o de ?leos leves; o sucesso deve-se aos baixos custos envolvidos e a facilidade de inje??o. O m?todo Toe-to-Heel Waterflooding TTHWTM utiliza uma configura??o de po?os injetores verticais completados no fundo do reservat?rio e po?os produtores horizontais completados no topo. O mecanismo de produ??o principal ? a segrega??o gravitacional em dist?ncias curtas. Este m?todo tem sido estudado desde o in?cio dos anos 90 e tem sido aplicado no Canad? com resultados positivos para ?leos levemente pesados, no entanto o m?todo ainda n?o tem sido utilizado no Brasil. Para verificar a aplicabilidade do processo no Brasil foi realizado um estudo de simula??o em reservat?rios de ?leo leve com caracter?sticas do Nordeste Brasileiro. O objetivo da pesquisa foi analisar quais os fatores operacionais que podem influenciar no processo. As simula??es foram realizadas utilizando o m?dulo STARS da Computer Modelling Group , com o objetivo de realizar estudos de m?todos de recupera??o avan?ada de ?leo. Os resultados obtidos neste trabalho mostraram que a configura??o de po?os aplicada para este caso apresentou uma leve melhora em rela??o ? configura??o convencional de 5 pontos (5-Spot) em termos de fator de recupera??o, no entanto, apresentou menores resultados na avalia??o econ?mica

Multistage hydraulic fracturing of horizontal wells continues to be a major technological tool in the oil and gas industry. Creation of multiple transverse fractures in shale gas has enabled production from very low permeability. The strategy entails the development of a Stimulated Reservoir Volume (SRV), defined as the volume of reservoir, which is effectively stimulated to increase the well performance. An ideal model for a shale gas SRV is a rectangle of length equal to horizontal well length and width equal to twice the half length of the created hydraulic fractures. This project focused on using the Multistage Transverse Fractured Horizontal Wells (MTFHW) for two novel applications. The first application considers using the SRV of a shale gas well, after the gas production rate drops below the economic limit, for low grade geothermal heat extraction. Cold water is pumped into the fracture network through one horizontal well drilled at the fracture tips. Heat is transferred to the water through the fracture surface. The hot water is then recovered through a second horizontal well drilled at the other end of the fracture network. The basis of this concept is to use the already created stimulated reservoir volume for heat transfer purposes. This technique was applied to the SRV of Haynesville Shale and the results were discussed in light of the economics of the project. For the second application, we considered the use of a similarly created SRV for producing hydrocarbon products from oil shale. Thermal decomposition of kerogen to oil and gas requires heating the oil shale to 700 degrees F. High quality saturated steam generated using a small scale nuclear plant was used for heating the formation to the necessary temperature. Analytical and numerical models are developed for modeling heat transfer in a single fracture unit of MTFHW. These models suggest that successful reuse of Haynesville Shale gas production wells for low grade geothermal heat extraction and the project appears feasible both technically and economically. The economics of the project is greatly aided by eliminating well drilling and completion costs. The models also demonstrate the success of using MTFHW array for heating oil shale using SMR technology.