The objective of the research presented in this paper was to examine direct evidence of well conditions to determine wellbore integrity factors and mitigation for oil and gas wells exposed to carbon dioxide (CO2) in the subsurface. This project involved identifying the nature and severity of well defects such as poor or permeable cement, microannulus occurrence, cracks, and mechanical defects, through a combination of sustained casing pressure testing and well history review. Two producing fields were used as case studies to explore wellbore integrity: a Michigan Basin site and an Appalachian Basin site. These sites contain wells that have been exposed to injected or naturally-occurring CO2 over several decades and are therefore good candidates for researching wellbore integrity and sustained casing pressure.
Gas sample analysis, field surveys of well conditions, cement bond logs, well records, and sustained casing pressure build-up tests were used to quantify wellbore integrity factors. This research improves understanding the viability of CO2 injection projects and safe, reliable, and environmentally responsible operations.
Growth in CO2-enhanced oil recovery (EOR) has led to an increased demand for information about operational safety and the integrity of wells that have been exposed to CO2 due to injection or natural sources. Addressing this concern requires knowledge of the wellbore construction and local geology in relation to potential for corrosion of wellbore materials and migration of CO2. These aspects factor into site characterization, field management, and well plugging, especially in the Midwest U.S. where many legacy oil and gas wells are located.
The scope of this paper is to use publicly sourced data as a starting point for production analysis of two distinct well populations. The well populations that will be examined are horizontal Marcellus Shale wells (1) frac'd earlier in time with a defined plug-to-plug stage spacing and (2) frac'd at the same time or later in time with 1.5 to 3 times the number of stages, a production acceleration technique known as Reduced Cluster Spacing (RCS).
Public production databases were used to create snap shots of completion activity over time. To speed work flow, a more robust and regularly updated commercially available database that contains both completion and production data was used. Two distinct populations of wells for analysis were identified. A conservative decline curve analysis (DCA) was made to forecast estimated ultimate recovery (EUR) for all wells using only public data. For selected wells, reciprocal production rate versus square root of time plots were generated.
This paper will attempt to answer the following questions: (1) were statistically meaningful populations of both stimulation techniques found to exist; (2) how much production uplift did RCS achieve both early on and later time; (3) was there a real increase in EUR; (4) was there a difference in stimulation efficiency; and, (5) what can we learn by plotting P10, P50, and P90 values and EUR distribution curves for specific well populations.
To the authors' knowledge this would be the first SPE paper to explore this topic over such large Marcellus Shale well populations in Pennsylvania.
Nath, Fatick (University of Louisiana at Lafayette) | Salvati, Peter E (University of Louisiana at Lafayette) | Mokhtari, Mehdi (University of Louisiana at Lafayette) | Seibi, Abdennour (University of Louisiana at Lafayette) | Hayatdavoudi, Asadollah (University of Louisiana at Lafayette)
Strain is a critical parameter in the calculation of elastic rock properties, yet its conventional methods for strain measurement has several deficinies. In this paper, we analyze the application of optical methods with Digital Image Correlation (DIC) technique to provide detailed information regarding fracture patterns and strain development with time under Brazilian testing condition. The effect of porosity, rock types, lamination, and saturation on tensile strength will be also discussed.
To examine the effect of rock type, 60 samples of sandstone (Parker, Nugget and Berea) and carbonate formations (Winterset limestone, Silurian dolomite, Edward Brown and Austin Chalk) were testedunder dry and saturated conditions and with regard to lamination angle in laminated samples. A Vic-snap photogrammetry system was employed to monitor the samples in non-contact manner while conducting indirect tensile experiment. DIC is based on the photogrammetry system, which helps to visualize and examine rock fracture pattern from the recorded images of the rock before and after deformation by assessing the strain development in samples.
The experimental results show that - (1) average tensile strength declines while increasing porosity for homogeneous, laminated, and heterogeneous rock specimens. (2) lower tensile strengths are observed in carbonate rock samples compared to the sandstones except Silurian dolomite; (3) saturation reduces the rock strengths, for isotropic samples, highest 28% decline in strength (Berea sandstone) observed; whereas, a larger decrease (65%) was observed in fully heterogeneous Edwards Brown carbonate samples; (4) increase of lamination angle (from 0° to 90°) impacts the tensile strength, average tensile strength was observed for Parker and Nugget sandstone greater in perpendicular to the lamination (9 = 90°) direction compare to that of parallel (9 = 0°); (5) fracture patterns examined for homogeneous rocks are almost centrally propagated and relatively linear; whereas, three different fracture patterns (central fracture, layer activation and non-central or mixed mode) investigated for laminated and heterogeneous samples; (6) Finally, DIC results illustrated the fracture initiation and propagation with consistent strain mapping. The homogeneous samples produced a uniform fracture strain until the diametrical split where for the laminated samples were influenced by planes of weakness, and fully heterogeneous anisotropic rocks produced winding and erratic fractures.
Conventional rock classification in carbonate reservoirs typically requires considerable amount of core data, which usually may not be available at the depth resolution required for each target interval. In cases of tight carbonate rocks with extremely low porosity (less than 5% in average) and permeability (less than 0.1 md), a reliable rock classification is essential for well stimulation modeling. Such rock classification should take into account depth-by-depth petrophysical, compositional, and elastic properties of the formation. In this paper, we apply an integrated rock classification technique to enhance (a) well-log-based estimates of petrophysical, compositional, and elastic properties and (b) selection of appropriate candidate zones for acid fracturing treatment design in a tight carbonate reservoir in northern slope of Tazhong Uplift, Tarim Basin, China.
We first perform multi-mineral analysis and estimate volumetric concentrations of minerals, porosity, and fluid saturations. Since shear wave sonic logs are not available in most of the wells, we estimate elastic moduli using effective medium models including self-consistent approximation and differential effective medium theory. Corrections including the impact of fluids are developed using Biot-Gassmann fluid substitution. The inputs to the effective medium models include (a) the petrophysical and compositional properties obtained from well logs, (b) bulk and shear moduli for each mineral and fluid component, and (c) shape of rock inclusions (i.e., grains and pores). Core measurements are used for cross validating the well-log-based estimates of elastic moduli and petrophysical properties. Accordingly, we proposed a rock classification technique using unsupervised neural network that integrated depth-by-depth volumetric concentrations of minerals, porosity, and elastic moduli. Finally, we derived permeability models in each rock type and estimated the permeability in the target depth intervals. Variogram analysis on well-log-based estimates of permeability provides correlation lengths as inputs to acid fracturing treatment modeling.
We successfully applied the technique introduced here to a challenging tight gas interval of Tarim field in China. The estimated porosity and permeability were in good agreement with laboratory core measurements. The identified rock classes were verified by core samples and thin sections. We estimated elastic moduli with average relative errors of approximately 13% compare to the core measurements. The estimated elastic moduli were used as a key input for modeling of acid-fracturing treatments and improved stimulation success.
The rock classification technique introduced here provides important input parameters for well stimulation modeling, gives insight into evaluation of acid fracturing in tight carbonate reservoir, and helps with selection of best candidate zones for acid fracturing treatment design.
The roughness of fractures may play an important role in affecting the migration and placement of proppants during hydraulic fracturing operations. Previous studies focused on investigating the proppant transport in smooth vertical fractures, which did not consider the effect of the fracture-surface roughness. We examine the migration of proppants in rough and vertical fractures and then quantitatively reveal the effect of roughness on the instantaneous proppant transport and final proppant placement. Two types of rock samples (marble and granite) are fractured with the Brazilian test and molded to manufacture 20 × 20 × 5 cm transparent replicas. The surface roughness of these rock samples was first characterized by fractal dimensions. Then, the dyed fracturing fluid with a given proppant loading was injected into the rough vertical fracture. In each test, the inlet pressures were continuously monitored in order to obtain the differential pressure across the fracture model while the proppants were being transported in the fracture. The process was videotaped to real-time track the proppant distribution in the rough fracture.
The proppant-transport behavior in the rough and vertical fracture was observed to be totally different from that in the smooth fracture. The major experimental findings include the following: 1) The proppant in a rough vertical fracture does not progress as a regular sand bank that commonly occurs in the smooth fracture, but rather an irregular-shape sand clusters with fractal characteristics; 2) In the rough and vertical fracture, the phenomenon of proppant bridging is visually observed, and such phenomenon is more likely to occur in the location with a larger roughness height. This implies rough fracture could promote a wider spreading of the proppant in the fracture compared to smooth fractures, and; 3) The existence of roughness enhances the vertical displacement of fluid containing proppants. These effects are also favorable for obtaining a better filling of the proppants in the fracture. Our experimental study reveals the mechanisms of proppant transport and distribution in real vertical fractures under the influence of roughness effect.
Well operation is one of the key foundations for optimal production of hydrocarbons from unconventional shale plays. However, optimal production practices do not follow the versatility of "one size fits all" phenomenon. Completion strategy, Pressure-Volume-Temperature (PVT) properties and petrophysical properties vary from play to play. Hence, the well operating practices should be custom tailored to suit the completion and fluid properties.
In this paper, we propose optimal shut-in practices for dry gas shale reservoirs. We elaborated our study from a Marcellus shale dataset. Marcellus shale dry gas window has in place fluid properties that differ from liquid rich reservoirs like Eagle Ford and Wolfcamp shales. Therefore, production best practices borrowed "as-is" from liquid rich reservoirs and applied to dry gas reservoirs (or vice versa) may not affect the well ultimate recoveries in a positive manner and in some cases, may even reduce the expected ultimate recoveries (EUR's).
We show that the practice of "well conditioning", "resting" or "soak-in" i.e. shutting in the well for a significant time after hydraulic fracturing and before connecting to pipeline as well as frequent shut-in impedes the water unloading from the dry gas reservoirs. This leads to reduction in matrix permeability with an additional skin introduced by water imbibition.
Our methodology by simultaneously history matching gas rate, flowing bottomhole pressure (FBHP) and water rates in a reservoir simulator. We observe that after shut-in, water to gas ratio (WGR) decreases and gas rate increases. However, this increased gas rate is accompanied with higher declines in rates and pressures and ultimately leads to lower EUR's. The reduction in EUR in our case is modeled as a function of water saturation increase in the matrix due to imbibition. Thus, EUR in our study is a function of duration of shut-in and the time in well life at which the shut-in occurs.
Experimental observations show that: (1) matrix permeability of clay rich shale samples are usually impaired / damaged by dilute HCl imbibition. This impairment is due to both the clay swelling and related issue of brine (within the dilute HCl solution) and rock-acid reaction. (2) Matrix permeability of calcite rich shales improved with dilute acid imbibition. (3) Effective fracture permeability of un-propped (natural fracture) calcite rich and clay rich shales are reduced by dilute acid imbibition, this is because of "rock softening" and "etching/smoothing" of fracture roughness on the "fracture faces". (4) Propped permeability of clay and carbonate rich shales decrease with brine imbibition, and permeability further decreased after dilute acid imbibition. The further decrease in permeability and porosity after acid imbibition is caused by three phenomena: (a) rock weakening by rock-acid reaction, (b) further proppant embedment during repeated testes vs. stress, and (c) scale precipitation. These observations are similar to results reported in
Modeling results show that: (1) For carbonate rich shale reservoirs, despite dilute acid injection/imbibition/fracturing can cause considerable damage to propped fractures and natural fractures (mainly due to rock softening/weakening, fracture roughness damage, and proppant embedment), it can still lead to considerable production improvement This is mainly caused by the matrix permeability improvement which leads to improvement in stimulated reservoir volume. (2) For clay rich shale reservoirs, both brine (slickwater) and dilute acid imbibition/injection/fracturing reduces hydrocarbon production, due to damages caused in to propped fractures, natural fractures, and matrix. Therefore, dilute acid injection or imbibition is recommended pre, post, or during hydraulic fracturing of carbonate rich shale reservoirs (but not for clay rich shale reservoirs) Moreover, slickwater fracturing in clay rich shale reservoirs can create considerable formation damage and decrease in hydrocarbon production, hence, dry gas (such as N2, CO2, LNG, etc.) might be an alternative solution hydraulic fracturing of in clay rich shale reservoirs.
With the increase in average lateral length for horizontal wells comes increased challenges for reaching total depth (TD) with the production casing. Any production interval left un-cased will not contribute to initial or ultimate production or be booked as reserves, which can have a major detrimental impact on the financials of these wells.
ALTISS Technologies has designed a patent pending aluminum casing concept to facilitate the installation of long cased laterals, and assist with landing casing at the total depth. Due to its low density and low modulus of elasticity, the aluminum casing is about half the buoyed weight and twice as flexible as comparable steel casing. These physical properties help the aluminum casing lighten the toe of the casing string and navigate through micro doglegs and tortuous wellbores.
The aluminum casing was designed with a focus on torque and drag reduction, to be used in limited quantities to maximize the benefits and ensure that casing reaches total depth. Analysis showed that 4,000 pounds of hook load could be added, without casing rotation, with as little as 160 feet of aluminum casing installed, in some cases. To ensure proper threaded connections with the low modulus aluminum, ALTISS designed its own 5 ½" premium threaded connection, which exceeded 56,000 ft.-lbs. yield torque in testing. Multiple aluminum tubular specimens were collapsed in a laboratory setting to validate equations which are not covered by API calculations, nor conventional closed form solutions (e.g. Timoshenko, Tamano). An experimental nano-coating is currently being evaluated that will protect the aluminum from potential forms of corrosion, including galvanic reactions and acid programs.
The advantages of installing aluminum casing may allow for eliminating expensive premium threaded connections needed for rotating casing, or alternatives such as floating casing. Ensuring the lateral is 100% cased improves initial production, allowable booked reserves, and ultimate hydrocarbon recovery of the well.
In this paper, an integrated analysis and design method is presented to understand and quantify the effect of particle jamming near the entrance of perforation/wormhole tunnel. An advanced wellbore-scale three dimensional numerical studies with a coupled computational fluid dynamics (CFD) and discrete element model (DEM) were performed to simulate different mechanisms involved in particulate diversion. The results of wellbore-scale simulation were translated into an engineering particulate diversion model, based on the proven diversion mechanisms from laboratory and simulation. The model is incorporated into an integrated carbonate acidizing simulator.
Generally particulate diversion is not used in carbonate acidizing because of the formation of the wormholes and potential difficulty in removing particles from the induced wormholes or perforation tunnel. The new degradable particulate system addresses the issue and presents an efficient approach to divert acid in carbonate stimulation. Detailed physics based simulation demonstrate that the induced wormholes or perforation would plug thru two distinct mechanisms: (1) temporarily seal the entrance of small scale wormholes or perforation with a combination of small and large particles, and/or (2) large particles bridge along tapered path of wormhole/perforation and forms a temporary filter cake on the mouth of opening. Either of these diversion mechanisms will decrease the injectivity locally and promote fluid diversion from inside of well into other normally under-stimulated locations.
The integrated simulator is used to optimize acid stimulation of a vertical wellbore and explain the impact of operational parameters and subsurface conditions on the stimulation efficiency. The model results showed that most optimized bullheaded treatment can be significantly improved by utilizing the particulate diversion system. It is shown that that the developed skin from jammed particulate provided considerable diversion. The results also demonstrated the relation between treatment pressure, the quality of diversion, and subsurface conditions (e.g. permeability, porosity, reservoir pressure and temperature).
A method is developed to detect the precursors of drilling events based on drilling data such as surface data, wellbore geometry data, lithology (formation characteristics), and downhole measurements from various downhole tools. The drilling events refer to interesting behavior of the drilling system detected or recorded, such as severe vibration, stuck pipe, fluid loss, sudden equivalent circulating density (ECD) changes, etc.
The method is based on various machine learning techniques to learn the changing trend of drilling parameters when the drilling events happen. Specifically, the drilling events are first extracted from massive drilling data using defined thresholds and/or criteria. Then, the time series of drilling parameters are represented by symbolic aggregate approximation (SAX). The patterns of these SAX strings are clustered by unsupervised learning and then used for pattern recognition with dynamic time warping (DTW). Finally, the searching pattern recognition is proposed to classify the changing trend of drilling parameters.
The traditional SAX method is not suitable for drilling data processing because it assumes that the data should be Gaussian distributed. With the modified SAX, two sets of SAX parameters are used to cluster the time series by unsupervised learning with dynamic time warping distance as measure. It is found that one set of SAX parameters (alphabet size of 5 and 15-data-point window) could yield more reasonable patterns, including flat, ramp up, ramp down, step up, step down, pulse up, and pulse down. The changing trends of drilling parameters are classified to the predefined patterns with shortest DTW distance by using searching pattern recognition method. Finally, several experiments are conducted to demonstrate the effectiveness of proposed method.
This is an innovative work to apply the data mining and machine learning techniques to drilling interpretation. It provides a useful way for the remote center to monitor the onset of abnormal drilling events and inform the drillers taking actions to optimize the drilling operation. In addition, it helps the drilling community to understand the triggers of challenging drilling events such as stick/slip, whirling, etc.