Oil production decline and excessive water production are prevalent in mature fields and unconventional plays, which significantly impact the profitability of the wells and result in costly water treatment and disposal. To seek for a sustainable development of those wells, reducing the operation cost and extending their economic lives, this paper presents a method of synergistic production of hydrocarbon and electricity, which could harvest the unexploited geothermal energy from the produced water and transfer heat to electricity in the wellbore. Such method is cost-effective, since it does not require any surface power plant facility, and it is replicable in numerous wells including both vertical wells and horizontal wells. By simultaneous coproduction of oil and electricity, the value of existing assets could be fully developed, operation cost could be offset, and the economic life of the well could be extended.
This recently proposed method incorporated thermoelectric power generation technology and oil production. In this method, electricity could be produced by thermoelectric generator (TEG) mounted outside of the tubing wall under temperature gradient created by produced fluid and injected fluids. The aim of this paper is to illustrate the economic practicability of oil-electricity coproduction by using thermoelectric technology in oil wells based on previously proposed design. We examined the technical data of high water-cut oil wells in North Dakota and collected required information with respect to performance thermoelectric power generations. Special emphasis was placed on the key parameters related to project economics, such as thermoelectric material, length of TEG and injection rate. Sensitive studies were carried out to characterize the impact of the key parameters on project profits. We showed that by simultaneously production of oil and electricity, $234,480 of additional value could be generated without interfering with oil production.
The proposed method capitalizes on the unexploited value of produced water and generates additional benefits. This study could provide a workflow for oil and gas operators to evaluate an oil-electricity coproduction project and could act as a guidance to perform and commercialize such project to balance parts of the operation cost and extend the life of the existing assets.
Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
Cement sheath is a critical barrier for maintaining well integrity. Formation of micro-annulus due to volume shrinkage and/or pressure/temperature changes is the major challenge in achieving good hydraulic seal. Expansion of cement after the placement is a promising solution to this problem. Expanding cement can potentially close micro-annulus and further achieve pre-stress condition because of the confinement. Primary aim of this paper is to investigate mechanical integrity of different pre-stressed cement system under loading condition.
To achieve the objectives, finite element modelling approach was employed. Three dimensional computer models consisting of liner, cement sheath, and casing were developed. Pre-stress condition was generated by modelling contact interference at the cement-casing interface. Three cement (ductile, moderately ductile, and brittle) were considered for simulation cases. Wellbore and annulus pressure were applied. Resultant, radial, hoop, and maximum shear stresses were investigated at the cement-pipe interface to assess mechanical integrity. For comparison purpose, similar simulations were conducted using cement sheath without pre-stress and cement system representing uniform volume shrinkage and presence micro-annulus.
For constant wellbore pressure, the radial stresses observed in all three types of cement system were practically similar and decreased as pre-stress was increased. Hoop stress also reduced with increase in compressive pre-load. However, their absolute values were distinct for different cement types. These results indicate that cement system with compressive pre-load can notably reduce the risk of radial crack failure by providing compensatory compressive stress. However, on the contrary, the maximum shear stress developed at cement-pipe interface, increased because of pre-load. This can compromise the mechanical integrity by reducing the safety margin on shear failure. Thus, the selection of expansive cement should be made after carefully weighing reduced risk of radial failure/debonding against the increased risks of shear failure.
This paper provides novel information on expanding cement from the perspective of mechanical stresses and integrity. Modelling approach discussed in this work, can be used to estimate amount of pre-stress required for a selected cement system under anticipated wellbore loads.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
Cement is a key element for successful drilling and completing of a well. From oil and gas wells to geothermal applications, cement is a major material ensuring zonal isolation. With an increase in global energy needs and an expected uptick in drilling and plugging and abandonment activities, evaluating and understanding cement properties is crucial, since these properties are used in various engineering designs and calculations. The objective of this paper is to present how Nuclear Magnetic Resonance (NMR) can be used to understand the cement hydration process and the development of key properties such as strength and porosity. NMR applications for cement include determination of porosity, water interactions, identification of hydration stages and C-S-H gel development with curing time. Since water is present in all cement slurries, NMR can potentially help to understand microstructural changes in cement during curing. Data from more than 600 cement specimens cured for more than a year are compiled. Standard cement properties such as UCS (unconfined compressive strength) are compared with NMR responses. In this paper, we document cement hydration and porosity changes through NMR measurements in samples with five different recipes. Our study also confirms a strong correlation between NMR response and cement strength.
This paper evaluates the impact of decision making and uncertainty associated with production forecast for 2000+ wells completed in Permian basin. Existing studies show that unconventional reservoirs have complex reservoir characteristics making traditional methods for ultimate recovery estimation insufficient. Based on these limitations, uncertainty is increased during the estimation of reservoir properties, reserve quantification and, evaluation of economic viability. Thus, it is necessary to determine and recommend favorable conditions in which these reservoirs are developed.
In this study, cumulative production is predicted using four different decline curve analysis (DCA) − power law exponential, stretched exponential, extended exponential and Duong models. A comparison between the predicted cumulative production from the models using a subset of historical data (0-3months) and actual production data observed over the same time period determines the accuracy of DCA's; repeating the evaluation for subsequent time intervals (0-6 months, 0-9 months,) provides a basis to monitor the performance of each DCA with time. Moreover, the best predictive models as a combination of DCA's predictions is determined via multivariate regression. Afterwards, uncertainty due to prediction errors excluding any bias is estimated and expected disappointment (ED) is calculated using probability density function on the results obtained.
In this paper, uncertainty is estimated from the plot of ED versus time for all wells considered. ED drops for wells having longer production history as more data are used for estimation. Also, the surprise/disappointment an operator experiences when using various DCA methods is estimated for each scenario. However, it appears that whilst Duong (DNG) method always overpredicts, power law exponential (PLE) decline mostly under predicts, the stretched exponential lies between DNG & PLE estimates and the extended exponential DCA demonstrates an erratic behavior crossing over the actual trend multiple times with time. In conclusion, profitability zones for producing oil in the Permian basin are defined implicitly based on drilling and completion practices which paves the path to determine the "sweet spot" via optimization of fracture spacing and horizontal length in the wells.
The outcome of the paper helps improve the industry's take on uncertainty analysis in production forecast, especially the concept of expected disappointment/surprise. This study suggests that effects of
This study presents a novel, integrated workflow to maximize recovery using PVT compositional modeling, history matching, and numerical reservoir simulation in a tight oil sand formation, the Second Bone Spring. Advancements in unconventional resource development have enabled the Delaware Basin to become highly significant. However, optimizing the development of each formation is still lacking in understanding. This study is one of multiple future studies over tight reservoirs in the Delaware Basin and exhibits a comprehensive approach. Properties that will be optimized are well spacing, reservoir parameters, and EOR feasibility.
To determine the behavior and optimize the development of each of these reservoirs, data from multiple sources was necessary. The data compiled consisted of reports from PVT analysis, completions design, petrophysical analysis, daily production and pressure, deviation surveys, structure and isopach maps, and well design. This data was then implemented into a 3D numerical reservoir simulator (CMG-GEM), first to confirm PVT output in a compositional simulation (CMG-WINPROP), then to simulate up to 20 years of production, and finally to use uncertainty analysis (CMG-CMOST) to optimize reservoir input parameters. Once a base case scenario was established, we then furthered our investigation of well spacing and EOR feasibility by setting up multiple different scenarios for each and running them for 20 years. EOR scenarios included 1-3 month huff-and-puff CO2, as well as low salinity water injection. Results are normalized per foot of completely lateral length and lab data is implemented in EOR simulations.
Our results confirm that reservoir parameters, once established after uncertainty analysis, have a large impact on both optimizing well spacing and EOR feasibility in the Second Bone Spring formation. With each well having very similar cluster spacing, proppant amount and type, and fracturing fluid and type, up to 250 feet of inter-well spacing is unaccounted for. Optimized models show that closer spacing of at least 150 feet can increase EUR estimates an average of 11.25%. An increase of 5-17% recovery is observed once a smaller spacing is implemented. EOR models showed that CO2 and low salinity water injection are viable candidates for the formation (7.25-9% increase for CO2, 6.25% for LSWI).
This integrated study refines our reservoir parameter estimates and helps identify potential to maximize recovery. It suggests that a tighter spacing is necessary to cover a larger portion of the reservoir, as well as showing that EOR is feasible. An improved understanding of the entire reservoir leads to better production and economic estimates.
The effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells.
The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries.
The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others.
As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations.
With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.
This study analyzes the production data from 2,755 horizontal wells in the Haynesville shale. Correlations were generated to predict 4,5,6, and 7-year cumulative productions from initial 6,12 and 24-months production data. These correlations can help in field development planning and economic analysis. The residuals (Predicted – Actual Cumulative Production) from these correlations were also analyzed and this technique can be used to identify wells affected by interference, refracturing, frac-hits, etc.
The cumulative production estimates from the developed correlations were also compared with the corresponding estimates from the DCA equations (seven different DCA methods used). The accuracy of prediction based on correlations developed in this study is at par with the various standard DCA methods published and used in the industry. The correlations are much faster to use and easier to implement for a large number of wells.
Another objective of the paper was to develop P10, P50 and P90 type curves for the Haynesville shale using the available production data. A subset of the total wells i.e. 150 wells evenly distributed throughout the study area, were used for predicting type curves. These type curves were generated and compared using different Decline Curve Analysis (DCA) models. The different DCA methods predicted an uncertainty of 5 to 27 % for the P10, P50 and P90 production profiles.
With the current applications of CO2 in oil wells for enhanced oil recovery (EOR) and sequestration purposes, the dissolution of CO2 in the formation brine and the formation of carbonic acid is a major cause of cement damage. This degradation can lead to non-compliance with the functions of the cement as it changes compressive and shear bond strengths and porosity and permeability of cement. It becomes imperative to understand the degradation mechanism of cement and methods to reduce the damage such as the addition of special additives to improve the resistance of cement against acid attack. Hence, the primary objective of this study is to investigate the effects of hydroxyapatite on cement degradation.
To investigate the impacts of hydroxyapatite additive on oil well cement performance, two Class H cement slurry formulations (baseline/HS and hydroxyapatite containing cement/HHO) were compared after exposure to acidic environments. To evaluate the performance of the formulations, samples were prepared and aged in high-pressure high-temperature (HPHT) autoclave containing 2% brine saturated with mixed gas containing methane and carbon dioxide. Tests were performed at different temperatures (38 to 221°C), pressures (21 to 63 MPa) and CO2 concentrations (10 to 100%). After aging for 14 days at constant pressure and temperature, the samples were recovered and their bond and compressive strength, porosity and permeability were measured and compared with those of unaged samples.
The results demonstrated that adding hydroxyapatite limits carbonation. Baseline samples that do not contain hydroxyapatite carbonated and consequently their compressive strength, porosity, permeability, and shear bond strength significantly changed after aging while hydroxyapatite-containing samples displayed a limited change in their properties. However, hydroxyapatite-containing samples exhibit high permeability due to the formation of microcracks after exposure to carbonic acid at high temperature (221°C). The formation of microcracks could be attributed to thermal retrogression or other phenomena that cause the expansion of the cement.
This article sheds light on the application of hydroxyapatite as a cement additive to improve the carbonic acid resistance of oil well cement. It presents hydroxyapatite containing cement formulation that has acceptable slurry properties for field applications and better carbonic acid resistance compared to conventional cement.