Development of an optimised integrated underbalanced drilling strategy for cuttings transport in gas-liquid flow through wellbore annuli.

Although understanding the relationship between gas-liquid two-phase fluid flows and the effects of the major drilling variables is critical to optimising underbalanced drilling (UBD) operations, to date, this has been an area of limited research and knowledge. This study contributes to the limited knowledge base by: 1) determining the key operational drilling parameters which shape the gas-liquid two-phase multiphase flow behaviour characteristics during UBD operations, 2) evaluating the most critical operational issues that have impacted the implementation of global UBD programmes, and 3) investigating the Newtonian and non-Newtonian gas-liquid two-phase flow patterns which affect the wellbore hydraulics and cuttings transport efficiency during UBD operations. Thus, this study developed a rigorous integrated strategy for maximising the efficiency of UBD for the transport of cuttings in gas-liquid two-phase flow through wellbore annuli. An experimental approach was applied to analyse and evaluate the relationship between the gas-liquid two-phase flow patterns and the major operational drilling parameters (gas and liquid flowrates, fluid rheology, inner pipe rotation, pipe inclination angle, pipe eccentricity and solid particle size and density) and to investigate their influence and interaction on the fluid flow dynamics and solids transport mechanisms in horizontal and inclined annuli. Experimental results revealed that drilling fluid flowrate along with fluid flow pattern are the most prominent parameters that strongly influence the cuttings transport efficiency within wellbore annuli. Annuli cleaning requirements for a concentric annulus was found to be lower than that required for an eccentric annulus for both Newtonian and non-Newtonian fluids. Pipe inclination angle was shown to affect hole cleaning, with the degree of its effect being significantly influenced by the drilling fluid properties, prevailing gas-liquid fluid flow pattern and cuttings transport mechanism. Moreover, inner pipe rotation was observed to improve cuttings transport in both horizontal and inclined eccentric annuli to varying extents. Experimental evidence was supplemented with a theoretical approach. Flow pattern dependent multi-layered mathematical models applicable for any level of pipe eccentricity were used for the different cuttings transport mechanisms existing in the different fluid flow patterns (dispersed bubble, bubble, and slug), offering a unique method to evaluate cuttings transport efficiency and wellbore hydraulics performance for UBD operations. A favourable comparison was observed between the experimental data and proposed flow pattern dependent multi-layered mathematical models with an error margin of ±15%. This research has generated new knowledge and created value through mapping the factors influencing particle transport and by evaluating the fluid-particle dynamics (fluid forces, gas-liquid fluid flow patterns and particle transport mechanisms) for flow in wellbore annuli. It has further identified and evaluated the effect of gas-liquid two-phase fluid flow patterns on fluid-particle transport dynamics which results in areas of preferential flows and stagnation zones. It also proposed a systematic solution to the governing equations for the simultaneous flow of gas-liquid two-phase fluids and solid particles in wellbore annuli. Overall, the mapping of the major operational drilling parameters and their influence and interdependencies on wellbore dynamics and cuttings transport efficiency in the context of gas-liquid fluid systems, provides a tool for the prediction of cuttings transport mechanism, determination of the stationary bed height, and calculation of the annuli pressure losses. Therefore, wellbore pressure evaluation and management and hole cleaning requirements for UBD operations can be addressed

Improved bottomhole pressure control for underbalanced drilling operations

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

Development of real-time early gas kick detection model

Gas kicks occur during oil and gas drilling operations due to pressure imbalances between reservoir pressure and bottomhole pressure. Uncontrolled gas kick results in blowouts which has severe consequences including death of rig personnel. For deepwater, High Temperature High Pressure, and depleted wells, early gas kick detection may mean the difference between a successful drilling operation and a catastrophic drilling operation. Modeling the physics of gas kicks is therefore an important aspect of well control in order to detect kicks and raise appropriate alarms that demand remedial action from the rig team. Also important is the quantification of the amount of kick already in the annulus and an estimation of the kick front, all in real time. Various kick models have been developed over the years to model wellbore-reservoir interactions and aid early detection of gas kicks. Some of these models and simulators are numerical and analytical; others are based on extensive collection of well data of kick events to model drilling events signatures including kicks of various sizes. In general, for non-data driven models, the accuracy of models depends on the amount of simplification done and the validity of the assumptions made. Steady state, semi-steady state and transient models exist, but if accurate detection is to occur in real-time, it is crucial that transient models are used, that the assumptions are valid, and that oversimplification is avoided in order to reflect as closely as possible, the complex physics of wellbore-reservoir interactions. The important issues to consider include the type of fluid property model used, such as compositional or black oil models; the type of frictional model used, such as Power law or Bingham plastic model; the flow regime considered; slip velocity between the phases, and the extent to which first principles are applied to problem solving, as opposed to using correlations. Our study is on real-time estimation of gas kicks during drilling using a two-phase, fully implicit, transient flow model in a vertical wellbore. The wellbore and reservoir are coupled, and a pressure gradient is introduced at the bottomhole causing gas influx into the wellbore. The gas front is then monitored in real-time as it is transported in the circulating mud to the surface pits. The model equations are the mud and gas continuity equations, the momentum conservation equation as well as sub-models, consisting of state equations and two-phase flow correlations, where needed. Much of the complex physics of gas kick is modeled, and the outcome of this research provides a tool for gas kick prediction, detection and control, and also for the estimation of the volume of kick occurring at the bottomhole in real-time.Mechanical Engineerin

Repurposing of disused shale gas wells for subsurface heat storage: preliminary analysis concerning UK issues

Development of many wells is envisaged in the UK in coming decades to exploit the abundant shale gas resource as fuel and petrochemical feedstock. Forward planning is therefore warranted regarding reuse of the resulting subsurface infrastructure after gas production has ceased. It is shown that this infrastructure might be repurposed for borehole thermal energy storage (BTES). Preliminary calculations, assuming an idealized cycle of summer heat storage and winter heat extraction, indeed demonstrate annual storage of c. 6 TJ or c. 2 GWh of energy per BTES well. Summed over the anticipated well inventory, a significant proportion of the UK's future heat demand might thus be supplied. This form of BTES technology has particular relevance to the UK, where the shale resource is located in relatively densely populated areas; it is especially significant for Scotland, where the resource coincides with a particularly high proportion of the population and heat demand

Bottom hole analyses of gas kick (inflow) and gas reservoir characterization while drilling underbalanced.

This study presents two new models developed to analyze gas flow between the reservoir and the wellbore while drilling underbalanced. Three drilling operational stages were considered in the analyses. These stages are the continuous drilling and mud circulation; suspension of drilling and mud circulation with the wellbore still opened; and, the shut-in of the wellbore. The first model, called gas bubbly model distinguishes the inflow pattern of gas into a liquid from that of liquid inflow into a liquid, while the second model, a wellbore pressure build-up model, is based on the concepts of increasing annular fluid density during well shut-in. The limitations of these models are the assumption of isothermal wellbore conditions, application of radial unsteady flow equation, and that none of the gas inflow has been produced.The models couple the viscous, surface tension, inertia, buoyancy, force of fluid ejection from the bit nozzles, and the reservoir forces at the wellbore-sand face contact to analyzing the three drilling operational stages. By incorporating these forces and conducting the analyses at the wellbore-sand face contact, practical characteristics of gas bubbly inflow into a denser fluid system is achieved, thus improving gas formation productivity evaluation while drilling. The improvements are achieved through the reduction of the wellbore effects such as the gas bubble coalescence and breakage, and bubble expansion and compression that are not possible to practically quantify during annular upward flow of gas bubbles.The chief technical contributions of this study are: (1) Models that take into account the practical characteristics of gas inflow into denser fluid systems are developed. This allows the gas inflow to be treated differently from the liquid inflow. (2) Quantitative analyses of gas inflow at the bottom of the hole are made possible by this study. This approach thus reduces the influences of the wellbore effects on the gas formation productivity evaluation, which is presently approached as the differences in the surface fluid injection rate and the annular outflow rate.Among many outcomes from the study are: (1) The radial flow equation of gas inflow into the wellbore during underbalanced should be applied deeper than a partially penetrated depth of ≤ 1 ft; (2) Porosity effect on cumulative gas production is not apparent for smaller drilled gas formation intervals, but for longer intervals, gas formations with lower porosity produce more gas volume than ones with higher porosity due to greater pore space compression. This is in agreement with published data

An Improved Foam Modeling Technique and Its Application to Petroleum Drilling and Production Practice

Foam is one of the most common used multiphase fluid in Underbalanced Drilling (UBD) and Managed Pressure Drilling (MPD). Because of its low density, high capacity of lifting and carrying cuttings, low cost and compatibility with formations, foam has become more superior than the conventional drilling mud when depleted reservoir pressure, severe lost circulation, or unstable borehole are encountered. In general, the success of foam applications rely on the understanding of the fundamentals of foam rheology in downhole conditions. Foam rheology has been studied for decades. Conventional foam rheological models such as Power Law, Bingham Plastic, Herschel-Bulkley to explain foam behavior usually fail to interpret the monitored circulating pressure changes in operation, not to mention foam behaviors in downhole. Understanding bubble size and foam texture impacts at different foam quality ranges in the foam model development become very significant. A new foam rheological model based on Low-Quality Regime (LQR) and High-Quality Regime (HQR) behaviors is developed. This new model, which originally came from comprehensive foam flow experiments, together with the visualization of foam texture and bubble distribution, is proved to be easily and conveniently implemented for industry use in this study. The model requires nine model parameters – three (uwRef, ugRef,DPRef) to define the transition region, four to capture Power-Law rheology in both HQR and LQR (KH, nH, KL, nL), and two to describe the sensitivity of steady-state pressure drops as a function of gas and liquid velocities in both regimes (mH, mL). With the newly developed foam model, we apply it in the following two foam applications in petroleum industry, in which the foam rheology and foam handling are the main concerns for successes. First of all, a foam drilling and wellbore clean-up application with foam is investigated. These scenarios consider foam circulation into 10000 ft long wells at different inclination angles with a long vertical, inclined, or horizontal trajectory. The results are compared with two existing foam modeling techniques, so-called Chen et al.’s model (based on the correlations for wet foams only) and Edrisi and Kam’s model (based on wet- and dry-foam rheological properties with five model parameters). The conclusions show that, with or without formation fluid influx, the new foam model demonstrates the robustness of the new modeling technique in all scenarios capturing foam flow characteristics better, whenever the situation forms stable fine-textured foams or unstable coarse-textured foams. Second, foam-assisted mud cap drilling for gas migration situation, which simulatesthe process with accurate foam characteristics when foams are used to suppress gas kicks under certain well and fluid conditions, is presented. The new foam model with Two Flow Regimes is used throughout the simulation process. The results show how mud-cap drilling parameters (such as pressure, foam density (or equivalent mud weight), foam velocity, and foam quality) change at different operating conditions and scenarios. Moreover, a set of field data from a wellbore clean-up with foam operation is demonstrated and the circulating pressure changes provide the evidence of Two Flow Regimes

Modeling Coupled Transient Transport of Mass, Momentum and Energy in Wellbore/Reservoir Systems

The total reserve of a hydrocarbon bearing formation and its ability to economically produce the fluids determine a reservoir’s development potential. Oil companies in the United States and abroad spend millions of dollars a year in well testing to estimate parameters related to these factors. A large fraction of these tests are surface “buildup” tests in which a producing well in the reservoir is “shut-in” either at the wellhead or at the bottom, or “drawdown” tests in which a well initially closed, is suddenly opened at the wellhead. The transient response of the pressure to these changes at the well bottom provides valuable information about formation properties. Shut-in at the bottom is usually very difficult and expensive, especially in the hostile environment of a high temperature/high pressure reservoir. Fluid flow in the wellbore is complicated by heat transfer between the fluid and the surrounding earth. Earth temperature generally increases with depth. Thus, as the hot fluid from the bottom flows upward, its temperature becomes higher than its surrounding causing heat loss from the wellbore. Conversely, when a well is shut-in at the wellhead, the warm fluid losses heat to the surrounding colder formation more rapidly than it gains it from the decreasing mass influx. Since fluid properties are temperature sensitive, pressure profile computation, which depends on fluid properties, is influenced by the fluid temperature profile in the wellbore. Thus, the transport processes in the wellbore are coupled. In this work we presented a transient wellbore/reservoir model for testing wells. We used a hybrid approach to couple the wellbore with the reservoir. The reservoir flow was modeled using the standard analytic approach, including superposition effects. The wellbore model, requiring simultaneous solution of the mass, momentum, and energy balance equations, used a finite difference numerical approach. Two simulators based on our model were developed: the forward simulator allowed us to simulate wellbore fluid temperature, pressure, and other variables at any depth and time for given reservoir parameters and well completion details; the reverse simulator allowed us to convert measured wellhead pressure and temperature to bottomhole pressure for subsequent analysis. Three field examples were used to demonstrate various applications of these two simulators. The good agreement between field data and predictions showed the quality of our simulators. We also identified the phenomenon of wellbore thermal storage. Wellbore thermal storage is the energy absorbed or released by the tubulars and cement sheaths, which is a significant fraction of the energy exchange between the wellbore and the formation at early time. A sensitivity study gave us further insights into the effect of various process variables on wellbore pressure and temperature. Thus, our simulators can be very useful in designing well tests as well as to augment conventional well test analysis

Analysis of diagnostic testing of sustained casing pressure in wells

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 well’s external integrity causing gas inflow from a high-pressure formation into the well’s 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