Intelligent Well Drainage and Interference Density Analysis Tool for Optimizing Infill Drilling

During the progressive development of mature fields, it is imperative to drill many infill wells to accelerate production and access bypassed oil. Optimizing the infill well spacing is always the concern to reduce interference with existing wells and improve recovery. In the present study, using intelligent data mining techniques, a new analysis and visualization tool has been developed and implemented to estimate and map drainage radius by well to assess the efficiency of the current development pattern and properly plan future wells. The tool deployed several performance-based techniques to estimate the contacted stock-tank oil initially in place (STOIIP) by each existing well, and outcomes can be compared between techniques for validation. The contacted STOIIP is then converted into an effective drainage radius by well using reservoir properties from the geo-cellular model. The evaluated reservoir is subdivided vertically into pay zones drained by the wells based on geological barriers/baffles to flow and connectivity across the zones. The tool estimates drainage radii of the wells produced from the reservoir using five different methods. The resultant Proved Developed Producing (PDP) reserves polygon maps are generated for the connected zones. The drainage radii of wells with behind-casing opportunities are estimated based on correlation and adjacent wells methods, and Proved Developed Non-Producing (PDNP) reserves polygon maps were generated. Well interference density is estimated based on overlapping drainage radii polygons with adjacent well locations, which has then been validated with production and pressure data from the wells. This paper describes the methodology by which the well drainage radii and well interference density can be estimated and implemented on a selected reservoir. This workflow can be successfully used to identify drained and undrained areas around the wellbore and opportunities for additional infill wells in the various pay zones of the reservoir. This exercise observed consistency in the drainage radii cumulative distribution from decline curve analysis methods and the No-Further-Activities (NFA) simulation case.

Automation of Well Correlation and Dynamic Synthesis for Efficient Reserves Estimation in Multi-Layered Oil and Gas Field

The studied field was discovered in 1974 and has been in operation for nearly 50 years. Being deposited within a deltaic environment with enormous multi-layer sand-shale series, the field is vertically divided into dozens of geological layers. Previous reserves estimation method of manually performing dynamic synthesis followed by volumetric calculation per layer basis has become less preferable amid increasing drilling and well intervention activities. Meanwhile, reservoir simulation is also inapplicable for reserves estimation due to the field's subsurface complexity. This paper shares an approach to automate well correlation and dynamic synthesis process by integrating static and dynamic data into Visual Basic for Application (VBA) based tool in order to efficiently estimate reserves and accelerate candidate selection for new well drilling and well intervention. Performing dynamic synthesis on a certain reservoir within a well of interest involves estimation of latest fluid status, pressure, water risks, recovery factor, and drainage radius by analyzing recent static and dynamic data from surrounding wells. As the static data and dynamic data from hundreds of existing wells are available in separate databases, the study commences with collecting, updating, filtering, organizing and integrating data into one reliable database. Afterwards, the automation tool is designed to quantitatively mimic the logics of performing well correlation and dynamic synthesis using weighting factors that characterize the reliability of data based on 3 parameters: distance to the well of interest, recentness of data, and sand similarity. Since these parameters have distinctive influence depending on the dynamic property being estimated, influence factors are introduced for each parameter and each dynamic property through trial & error process. Combining weighting and influence factors with available data results in the estimated dynamic properties that become input to volumetric calculation of reserves. In order to validate the model and tool, blind tests are carried out using data from recently drilled wells which are not included in generating the estimation. Pressure blind test shows good correlation between predicted and realized values, meaning that the tool is able to predict pressure accurately. Reserves estimation blind test also shows satisfying results both at reservoir and well level. Following successful blind tests, the tool has been utilized to aid engineers in proposing new wells and well intervention candidates. As a result, 8 wells were able to be proposed in a timely manner for the sanction of future development. This paper presents an efficient, novel and robust approach in estimating reserves for heterogeneous fields where reservoir simulation is inapplicable. The tool also allows straightforward update when adding data from new wells. However, further study is required for estimation in less dense areas where the amount of surrounding wells and data are insufficient.

Well Testing Based Method to Identify the Complex Fracture Geometry and Changing Drainage Radius Using an Efficient Boundary Element Model

Fracture geometries and drainage radius are important parameters for developing a reasonable development plan of a single fractured well. In some unconventional gas reservoir, some scholars observed the phenomenon of single well controlled reserves increasing through the material balance curve, and put forward the idea of district supply. In addition, owing to fracture hits, the fracture geometries of fractured wells are sometimes more complex. Thus, those complex factors bring challenges for parameter estimations. In order to study the variation of the drainage radius and complex fracture geometries in the single model, a well testing based model for a finite-conductivity fractured vertical well in radial composite reservoirs with dynamic supply and fracture networks is established. Based on "successive steady state method", the point source function, pressure superposition principle and boundary element method are used to solve the reservoir model, and the methods of discrete fracture and pressure superposition are used to solve the fracture model. By introducing the rate normalized pseudo-pressure and material balance time, the variable fluid flux is equivalent to the constant fluid flux. Combined with the inversion idea of well test, the drainage radius value and fracture geometries are solved by fitting the log-log curves of pressure response, and case studies are performed. The results show that the drainage radius increases with the increase of production time and finally tends to a certain value, and it has a good exponential relationship with time. Also, the fracture geometries of the typical well are multiple-radial fracture networks. Through the study of dynamic drainage radius, the controlled reserves of single well in unconventional gas reservoir can be better determined, and it can also provide theoretical basis for fracture evaluation, productivity prediction and enhanced recovery study of the same type of unconventional gas reservoir.

Reservoir Characterization of Fractured Gas Reservoirs Through The Integration of Dynamic Data

The productivity and performance of fractured reservoirs are strongly controlled by the fracture network distribution. Appropriate characterization of the effective fracture network is essential to accurately quantifying production forecast and reserves. Despite the known importance, it is still very challenging to properly evaluate natural fracture connection. The S Field is a giant gas field producing from fractured reservoirs which has the capability to produce more than 800 MMscfd at the field level and individual well deliverability as high as 300 MMscfd. With the historically strong data acquisition program and recent well results being outside of the expected range, the subsurface team has completed a re-characterization study to further understand the key subsurface uncertainties and find remaining or new resource potential. Considering non-uniqueness characteristic of dynamic data analysis, reservoir engineers may tend to repeat an existing interpretation over new reservoir studies, unless there is evidence to change. The downside to this reliance is the team may miss other possible interpretations of the model that were overlooked in the past. The new model may add a new point of view in the field characterization which could explain unexpected well results. In this dynamic data evaluation, the methods primarily rely on the short-term high precision data (Pressure Transient Analysis) and the long-term dynamic production (Rate Transient Analysis). These analyses make it possible to correctly evaluate the reservoir properties around the well, such as formation permeability, well skin, drainage radius and dynamic reserves to characterize the reservoir at a larger scale and reveal the reservoir connectivity and flow barriers in the prevailing heterogeneity. Apart from the dynamic data evaluation, this paper also addressed the integration of dynamic data with the 3D seismic interpretation and geological model which define faulting or fracturing relationships that drive the well productivity. Furthermore, it helps to refine the future development strategy options for the field.

Numerical Simulation of Borehole Parameters for Coal Seam Gas Pre-Drainage

Borehole parameters are quite important for gas drainage. This paper studies the impact of borehole diameter and time on gas drainage and performs numerical simulation on the distribution of gas pressure under the conditions of different borehole diameters and drainage times. The simulation results reveal that, as the borehole diameter increases, the gas drainage volume increases along with it and the gas pressure decreases, but such effect on gas drainage is limited. In terms of drainage time, the longer the drainage time, the greater the drainage impact scope. Taking a gas pressure drop of 51% as the indicator of the effective pre-drainage radius, the distance from the point with a gas pressure drop of 51% to the position of the borehole is the effective pre-drainage radius. When the pre-drainage reached the 30th, 45th, 60th, 75th, and 90th day, the effective pre-drainage radius was 1.04m, 1.29m, 1.51m, 1.68m, and 1.82m respectively. According to the numerical simulation results, the effective pre-drainage radius varies with the pre-drainage time, and the fitting analysis of the two indicates that the relationship between the two can be described by a power function.

Flow Behavior of Horinzontal Well Cmpleted within Two Sealing Fauts Inclined at Right Angle

At inception of a production rate regime, a horizontal well is expected to sweep oil within its drainage radius until the flow transients are interrupted by an external boundary or an impermeable heterogeneity. If the interruption is an impermeable heterogeneity or sealing fault, then the architecture of the heterogeneity must be deciphered in order to be able to design and implement an effective work-over or well re-entry to boost oil production from the reservoir. In this paper, therefore, the behavior of a horizontal well located within a pair of sealing faults inclined at 90 degrees is investigated using flow pressures and their derivatives. It is assumed that the well flow pressure is undergoing infinite activity, and each fault acts as a plane mirror. The total pressure drop in the object well is calculated by superposition principle. Damage and mechanical skin and wellbore storage are not considered. The main objective of our investigation is to establish identifiable signatures on pressure-time plots that represent infinite flow in the presence of adjacent no flow faults inclined at 90degrees. Results obtained show that the flowing wellbore pressure is influenced strongly by object well design, object well distance from each fault, and distance of each image from the object well. Irrespective of object well distance from the fault, there are three (3) images formed. Central object well location yields a square polygon, with two image wells nearer to the object well at equidistance from the object well, and the farthest image well to be 2d2. From the object well For off-centered object well location within the faults, a rectangular polygon is formed, with each image at a different distance from one well to another. Dimensionless pressure and dimensionless pressure derivative gradients during infinite-acting flow are (4.6052/LD) and 2/LD, respectively for all well locations within the faults.

Numerical simulation study on gas drainage by interval hydraulic flushing in coal seam working face

In order to solve the problem of difficult gas extraction in coal mine, a method of gas extraction from coal seam by interval hydraulic flushing is put forward. Based on the coal seam gas occurrence conditions of 7609 working face in Wuyang Coal Mine, the numerical simulation research on gas drainage by ordinary drilling and hydraulic flushing drilling was carried out by using COMSOL numerical simulation software. The results show that with the increase of hydraulic flushing coal quantity, the effective gas drainage radius also increases. The effective extraction radius of ordinary drilling is 0.5 m, and the effective extraction radius is 1.0 m, 1.2 m and 1.3 m respectively when the coal flushing quantity is 0.5t/m, 1.0t/m and 1.5t/m. As multiple boreholes are drained at the same time, the boreholes will affect each other, which will reduce the gas pressure and increase the effective drainage radius, the spacing between boreholes can be greater than twice the effective drainage radius of a single borehole when arranging boreholes. And the smaller the flushing interval, the more uniform the gas pressure reduction area. According to the numerical simulation results, the ordinary drilling and 1.0t/m interval hydraulic flushing test were carried out in the field. Through observation and analysis, the gas concentration of the interval hydraulic flushing drilling module was increased by 31.2% and the drainage purity was increased by 5.77 times compared with the ordinary drilling module. It shows that the interval hydraulic flushing drilling can effectively improve the gas drainage effect.

Experimental Study on Reasonable Spacing after Carbon Dioxide Presplitting in Low-Permeability Coal Seam

Gas disasters have been always a major hidden danger that affects mining safety in coal mines. Gas drainage by drilling is the fundamental method of gas control in coal mines. In view of the low-permeability coal seam, it is the basis of the safe and efficient production of the mine to take the measures of enhancing the permeability, improving the gas drainage efficiency, and shortening the drainage time. The 4−2 coal seam of the Jianxin coal mine in Shaanxi Province of China is a low-permeability coal seam. In order to obtain the reasonable hole spacing and the reasonable extraction time after the penetration enhancement, the pressure drop method is used to investigate the extraction radius. The results show that the gas pressure around the test hole decreases with time as a negative exponential function, and the effective radius of extraction increases with the increase of extraction time as a logarithmic function. Through the comparative analysis and variance analysis of the test data of the two drilling fields, it is proved that the data of the drainage radius of the two drilling fields are accurate and reliable. It is obtained that the reasonable spacing of the gas drainage holes is 8.10 m and the reasonable drainage time is 180 days after CO2 presplitting and permeability increase in the 4−2 coal seam of the mine.

Rate Decline Analysis of Horizontal Wells with Multiple Variable Conductivity and Uneven Distributed Fractures

In this paper, a new rate decline analysis model of horizontal wells with variable conductivity and uneven distribution of multiple fractures is proposed. By Laplace transformation, point source integration, and superposition principle, solutions of multiple infinite conductivity fractures in closed reservoirs are obtained. By coupling Fredholm integral equation of variable conductivity, linear equations of variable conductivity fractures in Laplace space are obtained. Gauss-Newton iteration, Duhamel convolution, and Stehfest numerical inversion method are used to obtain the bottom hole production solution. The accuracy of the results is verified by comparing with Eclipse software simulation. Then, the influence of some important reservoir and fracture parameters on the production is analyzed. The calculative results show that the smaller the fracture spacing is, the earlier the fracture begins to decline, the more the production will decrease; the change of different fracture length with the total fracture length unchanged has almost no effect on the production; the angle between fracture and x -axis has an important effect on the production; the smaller the angle between fracture and x -axis is, the stronger the interference between fractures is, the higher the production; the initial fracture conductivity affects the early production behavior, and the higher the initial fracture conductivity, the higher the production; the larger the fracture declines index, the lower the production, but the decreasing range gradually decreases with the increase of the decline index; the larger the reservoir drainage radius, the later the energy depletion stage, the higher the production. At last, a good fitting effect is obtained by fitting an example of oil field. The model proposed in this paper enriches the model base of rate decline analysis of fractured horizontal wells and lays a theoretical foundation for efficient development and practice of tight reservoirs.

Methodology Applied for Thickness Selection and Stored Heat Evaluation in Non-producer Geothermal Wells in Order to Its Investment Rescue

An assessment methodology of stored heat in rock formation surrounding to wellbore in geothermal systems is shown. Due to geothermal systems generally are nested in volcanic rock, it is characteristic its heterogeneous behavior. Proposed methodology starts since zone selection with possibilities of heat store. This methodology is focused to be applied in geothermal reservoirs with tendency to production decline, due to low permeability and unbalance between exploitation and water recharge. Because the high costs of drilling geothermal wells, methodology shown in this work is proposed to be applied in those with production decline or non-producers, in order to rescue its investment. The objective is to select the thickness with heat, evaluate its storage, design the appropriate instrumentation for its recovery, its energy conversion and rescue its investment done. The different designs for energy recovery using non-conventional methods to those, used habitually are reviewed. Each one of the variables for stored heat calculation was determined using technical tools of reservoir engineering. A parametric analysis about variables sensitivity (porosity and drainage radius) for determining thermal energy and corresponding electric energy of analyzed rock volume is done. Practical application of this methodology was carried out using data of one of wells of Los Humeros Mexican geothermal field.