Ford Wells Research Articles

Comparative study of elastic properties of marl and limestone layers in the Eagle Ford formation

Eagle Ford Formation has significant heterogeneity due to the existence of marl and interbedded limestone layers. The objective of this paper is to study the elastic properties of different layers in the Eagle Ford Formation. To achieve the goal, the relationships between compressional and shear velocities in marl and limestone layers were investigated in two representative Eagle Ford wells. These empirical equations can be used to estimate the shear velocity in Eagle Ford wells without sufficient well log data. Moreover, correlations between elastic properties and GR were obtained. Among all layers in the Eagle Ford Formation, marl layers of the lower Eagle Ford have the lowest averaged values of compressional velocity, shear velocity and dynamic Young’s modulus, while the limestone layers of the upper Eagle Ford have the highest averaged values of these three elastic parameters. In addition, the effect of elastic properties of shale layers on the aspect ratio of unconfined and confined fractures were evaluated. The influence of Young’s modulus contrast of shale layers on the aspect ratio of confined fractures was remarkable.

Case Study: Patent-Pending Rigless Chemical Process Enhances Oil and Gas Production in Eagle Ford

Hydrocarbon production losses resulting from parent-child well interactions during completion operations are a significant challenge in the Eagle Ford. A patent-pending rigless chemical frac hit remediation process was implemented in the Eagle Ford formation resulting in a 60% increase in oil production, a 30% increase in BOE reserves, and a payback in less than 4 months. A thorough engineering and lab study was conducted to design the process which addressed the damage mechanisms of capillary phase trapping, reduced hydrocarbon relative permeability, paraffin deposition, and minor scale deposition. Background and Challenge The Eagle Ford Shale play located across South Texas is a prolific unconventional resource producing approximately 967,000 BOPD and 6 Bcf/D of natural gas through 2021 (US Energy Information Administration). Like other unconventional reservoirs, Eagle Ford wells have high initial production rates but decline rapidly. Later-life production rates can significantly influence well economics and base production profitability. Production in the Eagle Ford rapidly started increasing around 2010 with the implementation of horizontal drilling and hydraulic fracturing. However, as operators started to develop their acreage, they quickly turned to drilling of infill wells, also known as child wells. Lindsay et al. (SPE 189875) reported that by the beginning of 2015, the number of child wells being drilled in the Eagle Ford surpassed the number of existing or parent wells. This resulted in an acceleration of child-parent interactions, defined as interwell communication between the child and the parent during the fracturing of the child well. Known as fracture-driven interference or frac hits, these interactions have been of intense interest in the industry due to the potential degradation of production in both the parent and child well. Miller et al. (SPE 180200) reported that in 1,210 instances studied in the Eagle Ford, the parent well experienced a negative production event approximately 41% of the time. Kairos Energy Services conducted a study on Eagle Ford parent wells that experienced negative production events from a frac hit to quantify the change in production. A total of six wells were analyzed where each had modern completions and were brought onto production in 2019 or later. Decline curve analysis was run on both the oil and gas streams before the frac hit to generate a forecast to compare against actual post-frac-hit production. Actual and forecast production was averaged across the six wells and production responses were analyzed 6 months before and after the frac hit. Fig. 1 shows the forecast vs. actual cumulative production for both oil and gas, respectively. The divergence in production post frac hit can be clearly seen, resulting in an average per well loss of 20,500 bbl of oil and 245,000 Mcf of gas 6 months following the frac hit. All wells showed a significant increase in water production directly after the frac hit, indicating hydraulic communication. The gas/oil ratio (GOR) was significantly suppressed, decreasing from 4,820 ft3/bbl to 3,850 ft3/bbl 6 months post frac hit. The 30-day average water cut also showed a sustained change, increasing from 46% to 63% 6 months post frac hit.

Teasing Meaning Out of a Tangle of Fracturing Data

The snarled red lines on the chart look more like a plate of spaghetti than a source of fracturing insights. It looks like a meaningless mess, which is generally how the ups and downs of difficult stages are viewed. To Adam Hoffman, a completion engineer for Chesapeake Energy, those 47-stages-worth of data look like a valuable opportunity. “We see so many stages with so many odd spikes and drops or chatter. We chop it off and say that was an odd stage. In my mind when we are looking at all those stages, we should wonder, ‘what was that pressure spike telling us,’” he said. That curiosity became a research project after Chesapeake encountered a spate of blockages in recently fractured Eagle Ford wells. The investigation into the cause of the casing damage led to a collaboration with Well Data Labs to look for connections between pressure changes and what is happening in the wells. Based on hundreds of stages of data from 19 wells fractured in the Eagle Ford, and later in the Powder River Basin, they reported finding a distinctive pressure signature that provides a reliable, but not foolproof, guide to when casing damage is likely. Well Data Labs has automated the search for those signatures as it looks for the meaning of the terabytes of fracturing data in this overwhelming number of seemingly random, squiggly lines. The oilfield data and software company is working on ways to monitor changes in the fracturing-fluid chemistry, the proppant intake into perforations, and an explanation for the pressure spikes seen before the pressure falls, said Jessica Iriarte, research manager at Well Data Labs. The troubleshooting and pressure analysis were covered in paper SPE 201484 presented at the 2020 SPE Annual Technical Conference and Exhibition (ATCE). It described how engineering trouble-shooting revealed that geological stresses were the likely source of problems in one case, and faulty pipe in the other. It followed up with data analysis, which used machine learning to identify distinctive patterns that provide an early warning of what is happening in the well faster and more objectively than a completion engineer studying the chart. Based on the troubleshooting, Chesapeake made changes that largely eliminated those costly problems. But it was also a costly learning process. In the Eagle Ford, they identified the underlying problem by investigating why multiple coiled-tubing runs were blocked while they were trying to drill out plugs after fracturing. When that happens, Hoffman said, “it can mean a week lost working past it.” Failure to drill out a plug can block access to the productive rock further down the lateral. A reliable automated treating-pressure analysis in the daily report could alert the completion team to problems while fracturing is in progress. They could then make adjustments on later stages and create a plan to limit the time lost when drilling out plugs on stages where they are likely to encounter tight sections.

Linking source rock to expelled hydrocarbons using diamondoids: An integrated approach from the Northern Gulf of Mexico

Nanodiamonds (diamondoids) are the ideal geochemical tool for hydrocarbon-source correlation in high-maturity fields since they are thermally stable and outlast biomarkers (molecular fossils), which deteriorate with thermal maturity. Diamondoids form in the shallow subsurface as organic material reacts with clay minerals in source rock, thereby preserving information about the precursor organic compounds and parent minerals. The unique suites of diamondoids generated by these combinations allow direct linkage between expelled hydrocarbons and source rock facies. We compared diamondoid distributions obtained from oils produced from both Eagle Ford Fm. and Austin Chalk Fm. in South-Central Texas, to rock extracts taken from equivalent intervals in a cored pilot hole. The targeted well is in the gas window where biomarkers are of limited use. Diamondoid distributions from oils produced from laterals in the Eagle Ford Fm. and the Austin Chalk Fm. matched extracts from those formations, proving that local sourcing is recognizable in expelled hydrocarbons.A second phase of this project included a direct comparison of results from pilot hole extracts to diamondoids analyzed from 15 oils selected from producing Eagle Ford wells. We showed a close match between the diamondoid chemistry of produced oils regionally and source samples from the Eagle Ford Formation in the cored pilot well. However, samples from immediately adjacent formations (Buda and Upson) were discordant, containing higher concentrations and different distributions of diamondoids when compared to the Austin and Eagle Ford systems.These results spurred a third phase of investigation that included generating diamondoid data from extracts of known Mesozoic Northern Gulf of Mexico (NGoM) source rocks stratigraphically beneath the Austin and Eagle Ford system. These included the Aptian-Albian Pearsall group and several Jurassic formations (Oxfordian Smackover Fm., Kimmeridgian Haynesville Fm., and Tithonian Bossier Fm.). The outlier samples from phases 1 and 2 are matched with deeper source rocks when comparing their diamondoid geochemistry to those of extracts from cored Jurassic source samples. These Jurassic intervals and migration pathways were then vetted with seismic data and integrated attribute analysis.The results of this work show: 1.expelled hydrocarbons can be linked to parent source rock using diamondoid composition; 2. diamondoids can be used to discriminate co-sourcing in intervals where routine biomarker analyses would fail; 3. Samples of well-known Mesozoic source rocks in the northern Gulf of Mexico (Cenomanian-Turonian Eagle Ford Fm., Tithonian Bossier Fm., Kimmeridgian Haynesville Fm., and Oxfordian Smackover Fm.) can be independently recognized using diamondoids, and 4. seismic anisotropy and fluid escape attributes helped delineate both deep-seated, through-going faults and intervals of high fracture density, allowing for connectivity and migration from the deeper source rocks illuminated by diamondoid analyses.

Analysis of fluid property variations across the Barnett and Eagle Ford Shale using fuzzy logic

The objective for this study is to perform an investigation of the areal and vertical geospatial fluid property variations across the Barnett and Eagle Ford based on publicly-available PVT data (97 Barnett wells and 153 Eagle Ford wells). A modified multi-contact recombination procedure has been implemented to the PVT data of the reported well stream compositions for Barnett to improve estimates of in-situ reservoir composition. The Eagle Ford data were utilised without modifications as this shale play is known to be highly under-saturated. The results of modified multi-contact recombination procedure for Barnett are plotted on a ternary diagram and show that the majority of the wells were dry gas to retrograde gas. For Eagle Ford, ternary diagrams indicated the fluid type, vertical variations of OGR, C7+ and API gravity. Maps were created to review areal variations of these properties (API gravity, C7+, and initial OGR). The study was further speculated by applying fuzzy pattern recognition algorithms. The application of fuzzy logic provided additional insight to the reservoir fluid's PVT behaviour in understudy shale formations. [Received: August 23, 2018; Accepted: May 6, 2019]

Analysis of fluid property variations across the Barnett and Eagle Ford Shale using fuzzy logic

The objective for this study is to perform an investigation of the areal and vertical geospatial fluid property variations across the Barnett and Eagle Ford based on publicly-available PVT data (97 Barnett wells and 153 Eagle Ford wells). A modified multi-contact recombination procedure has been implemented to the PVT data of the reported well stream compositions for Barnett to improve estimates of in-situ reservoir composition. The Eagle Ford data were utilised without modifications as this shale play is known to be highly under-saturated. The results of modified multi-contact recombination procedure for Barnett are plotted on a ternary diagram and show that the majority of the wells were dry gas to retrograde gas. For Eagle Ford, ternary diagrams indicated the fluid type, vertical variations of OGR, C7+ and API gravity. Maps were created to review areal variations of these properties (API gravity, C7+, and initial OGR). The study was further speculated by applying fuzzy pattern recognition algorithms. The application of fuzzy logic provided additional insight to the reservoir fluid's PVT behaviour in understudy shale formations. [Received: August 23, 2018; Accepted: May 6, 2019]

Improved EUR prediction for multi-fractured hydrocarbon wells based on 3-segment DCA: Implications for production forecasting of parent and child wells

A substantial number of methods has been proposed as part of the quest for better production forecasting and hence more accurate reserves estimations, especially for multi-fractured shale wells producing either gas or liquids (or both). However, none of the current methods stand out to be robust and practical enough to give reliable results for all field cases. The current study proposes a novel 3-segment decline curve analysis (DCA) method that uses the unique flow regime sequence of shale wells to delineate the periods for each of the three segments used in the DCA. The production data of 6 Eagle Ford wells (4 parents and 2 infills) was modeled with over 95% history matching quality. The proposed method, validated using hind-casting, proved to be extremely successful in predicting the production of the child wells, when production data is available from either parent wells or first generation child wells. The proposed method is based on the widely-used Arps' equation and honors the principal flow regimes recognized in recent studies. The improved history matching capability of the proposed method leads to a much reliable production forecast. Hence, the uncertainty in the reserves estimations significantly reduces, which is why this study argues for conclusive categorization of the estimated reserves based on type curves of later generation parent wells as P90 (proved reserves) rather than P50 (proved plus probable reserves).

Evaluating Fracture Volume Loss During Flowback and Its Relationship to Choke Size: Fastback vs. Slowback

Summary In this study we estimated the initial effective fracture pore volume (Vfi) and fracture volume loss (dVef) for 21 wells completed in the Montney and Eagle Ford formations. We also evaluated the relationship between dVef and choke size. First, we applied rate-decline analysis to water-flowback data of candidate wells to estimate the ultimate water recovery volume, approximated as Vfi. Second, we estimated dVef using a fracture compressibility relationship to evaluate the fracture volume loss of the Eagle Ford wells. Third, we investigated the effect of choke size on dVef for the Eagle Ford fastback and slowback wells. Semilog plots of flowback water rate vs. cumulative water volume show straight-line trends, representing a harmonic decline. The estimated Vfi accounts for approximately 84 and 26% of the total injected water volume (TIV) of the Montney and Eagle Ford wells, respectively. The results show that approximately 10% of the fracture volume is lost during flowback. This loss in fracture volume predominantly happens during the early flowback and becomes minimal during the late flowback period. The results show a relatively higher dVef for fastback (a flowback process with a relatively large choke size) wells compared with that for slowback (a flowback process with a relatively small choke size) wells. In this study we proposed a method to estimate the initial fracture volume and investigated the loss in fracture volume during the flowback process. Analyses of the field data led to an improved understanding of the factors that control water flowback and the effective fracture volume.

Variable Exponential Decline: Modified Arps To Characterize Unconventional-Shale Production Performance

Summary Different decline-curve-analysis (DCA) methods have been proposed to predict the production performance of both conventional and unconventional-shale reservoirs. These methods range from empirical to semiempirical and theoretical. The different methods were developed using specific data sets and have their own assumptions and limitations, and thus are not universally applicable. This study shows that a DCA method should be capable of simultaneously modeling the flow regime prevalent around the well and the changes in reservoir properties with time, to be able to successfully represent the production performance of the well and predict future performance. In shales, flow regimes can be linear, bilinear, multifracture linear, post-linear, stimulated-reservoir-volume (SRV) -dominated boundary flow, or compound linear. The change in fracture conductivity caused by fines migration, embedment, crushing, diagenesis, and change in stresses because of production is another important phenomenon for which a DCA method must account. This study critically analyzes various proposed historical DCA methods with respect to their capability to model fracture-flow regimes and changes in fracture conductivity with time. Upon close examination, it was found that both the linear-flow regimes and changes in fracture conductivity with time follow a power-law function. Thus, the reason for the successful application of the Arps (1944) hyperbolic, power-law-exponential (PLE), stretched-exponential-decline (SEPD), and Duong (2010) methods is that decline rates in these methods are a power-law function or can be closely approximated by a power-law function. A new simplified decline-curve equation is proposed by modifying the existing Arps exponential-decline equation, where the constant-decline rate is replaced by a power-law-function variable decline rate. The application of this method is shown using production data from Haynesville Formation and Eagle Ford Formation shales. The average error in cumulative-production prediction for 20 wells was found to be only 3% in Haynesville wells and 2% in Eagle Ford wells. This method is very robust and can account for different flow regimes and changes in fracture conductivity with time.

High-resolution visualization of flow velocities near frac-tips and flow interference of multi-fracked Eagle Ford wells, Brazos County, Texas

This study outlines a workflow that combines reservoir characterization and decline curve-based production analysis with a physics-based drainage model that quantifies where fluid is drained from, based on the fracture treatment architecture. Decline curve analysis, applied to production data from four multi-fracked wells in the Eagle Ford formation (Brazos County, East Texas), provides forecasts for the estimated ultimate recovery (EUR). About 50% of EUR is realized in the first 1000 days (∼3 years) of the well-life. The drainage model shows where in the reservoir the produced fluid is actually drained from, based on the estimated reservoir parameters. This study includes several fundamental assessments of factors that may impact any drainage model, such as (1) the pressure front propagation time responsible for the depth of investigation, (2) pressure effects due to up-scaling of fracture patterns into a reduced number of fractures, and (3) interaction of fluid velocity patterns with pressure depletion zones. The drainage model for the Eagle Ford wells in our case study suggests that the first generation of hydraulic fractures recovers less than 1% of the original oil in place. With recovery factors so low, a repetitive schedule of periodic refracking the wells - provided the first refracks prove successful - is highly recommended.

Benchmarking EUR estimates for hydraulically fractured wells with and without fracture hits using various DCA methods

Various decline curve analysis (DCA) methods can be applied to forecast the production performance of hydrocarbon wells, including horizontal wells stimulated with hydraulic fracturing. Yet, which method is more preferable remains in doubt. The objective of this study is to evaluate various DCA methods by history matching and hindcasting both synthetic and field production data in order to assess for each method the reliability of production forecasts and the estimated ultimate recovery (EUR). Five DCA methods have been evaluated because of their computational simplicity and broad application. These methods are the Modified Hyperbolic Decline model (MHD), Duong model, Logistic Growth Analysis Model (LGM), and the Power Law Exponential (PLE, with D∞=0 and D∞=∞) Decline models. Each method was evaluated using three data sets: synthetic shale oil production rates based on a CMG reservoir model using Eagle Ford reservoir characteristics, data from producing Eagle Ford wells and from Austin Chalk wells. The hindcast method was applied to the Eagle Ford synthetic wells to establish the EUR deviation between the synthetic reservoir model production forecast and the various DCA methods. The weighted residuals of history matched production rates for Eagle Ford indicate that the MHD and Duong models give the lowest matching errors (as low as 1.32%) and the highest EUR estimations (as high as 3,447,609 stb). The PLE model (with D∞≠0) gives the most conservative EUR estimation, and also the least reliable history matching method (on our Eagle Ford data sets), which therefore is the least preferable DCA method. For the Austin Chalk wells in our study, all methods generate fairly similar EUR predictions with similar matching errors (from 13% to 15%) so that the DCA method preference becomes indifferent. This study also touches upon the relationship between DCA results when well interference occurs due to various hydraulic fracture hits. Shale wells that primarily contain hydraulic fractures and few natural fractures (Eagle Ford) give the most reliable forecasts using the MHD and Duong DCA methods. However, wells in the Austin Chalk, a naturally fractured reservoir, show little difference between the forecast accuracy from the various DCA methods.

Shale EOR Works, But Will It Make a Difference?

When EOG Resources disclosed that it had found a way to get from 30 to 70% more oil from Eagle Ford shale wells, it set off a race among competitors looking for a low-cost way to add reserves by injecting natural gas. It has been little noticed because few companies have said anything publicly about it. But university researchers and service companies are seeing widespread interest from companies that are trying to figure out how EOG uses gas injection to increase production and whether those gains can be sustained long enough to add reserves. Research interest in gas injection enhanced oil recovery (EOR) persuaded David Schechter, a petroleum engineering professor at Texas A&M University, to equip his lab that has been used to test carbon dioxide (CO2) for EOR to safely observe how natural gas affects reservoir rock. “Basically everyone with a substantial acreage position is working on unconventional oil EOR now,” said Schechter. “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR,” said Deepak Devegowda, an associate engineering professor at the University of Oklahoma. The question facing EOG and its competitors is, can they take a method that improves results from some of its best wells, and use it on a far larger scale to increase overall recoveries in unconventional formations where more than 90% of the resource is left behind. Companies would like to understand and simulate it and, most importantly, they are looking for clues on how EOG did it. “A whole bunch of folks are watching what other people are doing,” Devegowda said. Companies and researchers are using statistical analysis to determine patterns in production data filed with the Texas Railroad Commission to try to figure out how EOG is using natural gas injection. Among those looking is Todd Hoffman, an associate professor from Montana State, who was initially skeptical of EOG’s claims. After studying the data, Hoffman said that EOG clearly is “seeing huge increases in added oil production.” He is now working on a paper based on the disclosures. As for how he figured out which of EOG’s more than 7,000 Eagle Ford wells to study, he said, “I really had to dig around to find it. I talked to a number of companies planning pilots, doing pilots, in the planning stage, trying to do the same thing,” he said.

Pump-Stroke Optimization: Case Study of Twenty-Well Pilot

Summary Pump-stroke optimization (PSO) was developed to address problems encountered when rod pumping in rapidly changing flow regimes was observed with oil production from horizontal wellbores. Current Rod-Pump Controller (RPC) technology was developed for vertical wells. RPCs integrated with a variable-frequency drive (VFD) (hereafter, referred to as RPC-VFD) are often applied to horizontal wells. However, the results are often frequent full-spectrum speed changes and excessive low-pump-fillage events; both are undesirable. A method that operators use to mitigate this problem is to manually reduce the maximum-working-speed setpoint to a value slightly above that required to handle all the daily production. This intervention must be performed routinely, and is counterproductive should the well see increased deliverability caused by events such as downtime or offset fracturing. PSO replaces human intervention by regularly adjusting the maximum working speed on the basis of analysis of several hours of observed pumping speeds and low-pump-fillage events. Some RPC-VFDs allow for the downstroke to operate at a slower speed than the upstroke. For RPC-VFDs with this feature, the PSO device decreases the downstroke pumping speed preferentially, leaving the upstroke pumping speed unchanged until an operator set differential is reached. This practice results in less pump slippage, as well as additional time for evolving gas to exit the rod pump's gas anchor. This results in fewer strokes per day for the same production, which results in less downhole wear and less power consumption. Field trials began in two Eagle Ford wells in March of 2015, with initial very successful results presented at an industry workshop in September 2015. An expanded twenty-well Eagle Ford pilot test was begun on 3 December 2015. Rather than handpicking wells that were similar to the initial two-well pilot, a wide range of production rates was chosen. After 45 days of operation, the following indicators were reviewed by the operator to determine overall success or failure: Algorithm convergence (indicating successful PSO-device-supplied pumping speeds) Greater average pump fillage (earlier load transfer being better for downhole equipment) Fewer strokes per day without production loss (provided by greater fillage and less slippage) Higher bottom minimum stress in final rod taper (indicating reduced buckling tendency) Less electrical-power consumption The data were obtained with standard industry supervisory control and data-acquisition (SCADA) software, as well as by manually reading power meters. In summary, the operator deemed ten wells highly successful, five marginally successful, and five not successful. The reasons contributing to success and failure will be explored to obtain higher success rates in future applications.

Can Austin Chalk Expansion Lead to Revival?

Interest is growing in drilling the Austin Chalk formation, with oil and gas companies hopeful that applying the latest unconventional resource development technologies can open a new chapter of expansion in a historically prolific play that dates to the 1920s. Much of the new drilling is in areas of the Chalk that overlie some of the most active parts of the Eagle Ford Shale play in south Texas. Drillers there are taking advantage of the additional stacked play opportunities that can often be drilled with the same rigs and crews they are using in the Eagle Ford and sometimes in the same well. Some operators may have also drilled in the Chalk during the depths of the industry downturn to hold leases and temporarily defer deeper Eagle Ford wells. The Austin Chalk extends from Mexico across south and east Texas and a large portion of Louisiana to Mississippi. The history of the Chalk play has seen several booms, the last one coming in the 1990s with the introduction of horizontal drilling. Cumulatively, the formation has produced 1.7 billion BOE with approximately 9,500 wells having been drilled there. Abundant Resources There is good reason to believe that abundant oil and gas resources remain in the Austin Chalk. The United States Geological Survey released a study of four Austin Chalk-area assessment units (AUs) in 2010 that estimated mean undiscovered resources for the Austin Pearsall-Giddings AU of 879 million bbl of oil, 1.3 Tcf of gas, and 106 million bbl of natural gas liquids (NGLs). Three other AUs were estimated to hold a combined mean 78 million bbl of oil, 2.3 Tcf of gas, and 257 million bbl of NGLs. Among the most active participants in the latest Austin Chalk play have been EnerVest, EOG Resources, Encana, and Murphy. Other companies active in the Chalk include GulfTex Energy, ConocoPhillips, Devon Energy, Marathon, Abraxas Petroleum, and Chesapeake. EnerVest, which acquires, develops, and operates oil and gas fields on behalf of its institutional investors, is the largest producer in the Austin Chalk. The company built a substantial position there beginning with its 2007 acquisition of Anadarko’s holdings in Texas’ Giddings field, which has been producing since the 1930s. EnerVest’s move into the Chalk came years before most other current players. In the Giddings field, as in certain other parts of the Austin Chalk, the formation lies above the Eagle Ford. But Eagle Ford development has been minimal there, compared with core Eagle Ford activity taking place from 20 to 80 miles southwest of the field.

GHGfrack: An Open-Source Model for Estimating Greenhouse Gas Emissions from Combustion of Fuel during Drilling and Hydraulic Fracturing.

This paper introduces GHGfrack, an open-source engineering-based model that estimates energy consumption and associated GHG emissions from drilling and hydraulic fracturing operations. We describe verification and calibration of GHGfrack against field data for energy and fuel consumption. We run GHGfrack using data from 6927 wells in Eagle Ford and 4431 wells in Bakken oil fields. The average estimated energy consumption in Eagle Ford wells using lateral hole diameters of 8 (3)/4 and 6 (1)/8 in. are 2.25 and 2.73 TJ/well, respectively. The average estimated energy consumption in Bakken wells using hole diameters of 6 in. for horizontal section is 2.16 TJ/well. We estimate average greenhouse gas (GHG) emissions of 419 and 510 tonne of equivalent CO2 per well (tonne of CO2 eq/well) for the two aforementioned assumed geometries in Eagle Ford, respectively, and 417 tonne of CO2 eq/well for the case of Bakken. These estimates are limited only to GHG emissions from combustion of diesel fuel to supply energy only for rotation of drill string, drilling mud circulation, and fracturing pumps. Sensitivity analysis of the model shows that the top three key variables in driving energy intensity in drilling are the lateral hole diameter, drill pipe internal diameter, and mud flow rate. In hydraulic fracturing, the top three are lateral casing diameter, fracturing fluid volume, and length of the lateral.

Multiphase Rate-Transient Analysis in Unconventional Reservoirs: Theory and Application

Summary In unconventional reservoirs, production data are generally analyzed by use of rate-transient techniques derived from single-phase linear-flow models. Such linear-flow models use rate-normalized pressure, which is pressure drop divided by reservoir-flow rate vs. square root of time. In practice, the well-fluid production includes water, oil, and gas. The oil can be light oil, volatile oil, and gas/condensate as in the Bakken, Eagle Ford, and Barnett, respectively. Thus, single-phase analysis needs modification to account for production of fluid mixtures. In this paper, we present a multiphase-pressure-diffusivity equation to analyze multiphase flow in single- and dual-porosity models of unconventional reservoirs. Our approach is similar to the work presented by Perrine (1956); however, our approach has a theoretical foundation, whereas Perrine (1956) used pragmatic engineering analogy for constant flow rate in vertical wells only. In addition to oil, gas, and formation brine, our method accounts for gas/condensate production, and the flowback of the injected hydraulic-fracturing fluids. Overall, our proposed approach is more comprehensive than the single-phase models but maintains the simplicity of the conventional methods. Our paper includes diagnostic plots of rate-normalized well pressure for light oils and gas/condensates in unconventional reservoirs. Data from two Bakken and two Eagle Ford wells will be presented to demonstrate the usefulness of our approach. In addition to the mathematical analysis of flow-rate and pressure data, we will present the effect of well-stimulation and fluid-lift methods on the flow-rate characteristics of Bakken and Eagle Ford wells.

Geomechanical modeling of hydraulic fractures interacting with natural fractures — Validation with microseismic and tracer data from the Marcellus and Eagle Ford

We have developed a new geomechanical workflow to study the mechanics of hydraulic fracturing in naturally fractured unconventional reservoirs. This workflow used the material point method (MPM) for computational mechanics and an equivalent fracture model derived from continuous fracture modeling to represent natural fractures (NFs). We first used the workflow to test the effect of different stress anisotropies on the propagation path of a single NF intersected by a hydraulic fracture. In these elementary studies, increasing the stress anisotropy was found to decrease the curving of a propagating NF, and this could be used to explain the observed trends in the microseismic data. The workflow was applied to Marcellus and Eagle Ford wells, where multiple geomechanical results were validated with microseismic data and tracer tests. Application of the workflow to a Marcellus well provides a strain field that correlates well with microseismicity, and a maximum energy release rate, or [Formula: see text] integral at each completion stage, which appeared to correlate to the production log and could be used to quantify the impact of skipping the completion stages. On the first of two Eagle Ford wells considered, the MPM workflow provided a horizontal differential stress map that showed significant variability imparted by NFs perturbing the regional stress field. Additionally, a map of the strain distribution after stimulating the well showed the same features as the interpreted microseismic data: three distinct regions of microseismic character, supported by tracer tests and explained by the MPM differential stress map. Finally, the workflow was able to estimate, in the second well with no microseismic data, its main performance characteristics as validated by tracer tests. The field-validated MPM geomechanical workflow is a powerful tool for completion optimization in the presence of NFs, which affect in multiple ways the final outcome of hydraulic fracturing.

The Shale Evolution: Zipper Fracture Takes Hold

Zipper Fractures A horizontal well completion method known as zipper fracturing has been rapidly adopted over the last couple of years by companies in the Eagle Ford shale of south Texas. Instead of drilling and hydraulically fracturing one well at a time, the zipper method involves drilling multiple wells from a pad site and then hydraulically fracturing a stage in one well, while getting ready for the next, as wireline and perforation operations take place in another. The multiwell completion method earns its name from the zipper-like configuration of the fracture stages from wells drilled with relatively tight spacing. This shaves days off the time it takes to complete a multiwell pad. Many companies in south Texas are now using the completion method on almost every new pad site they drill into, saving tens of millions of dollars per year while accelerating the development of their well inventories. But the big prize may be that zipper fractures are increasing initial production and estimated ultimate recovery rates when designed so that the fractures stimulate the most reservoir volume possible. Tulsa-based WPX Energy, an independent operator of 160,000 acres in the San Juan Basin of New Mexico, told investors this summer that when the company switched to zipper fracturing, it averaged 420 B/D of oil production compared with 388 B/D from single-well completions. While not entirely sure if zipper fracturing is the direct cause of improved production, WPX said it expects that is the case. Mukul Sharma, a professor and chair in the petroleum department at the University of Texas at Austin (UT), said field data from Eagle Ford wells make it clear to him that zipper fractures are indeed improving initial production rates and the estimated ultimate recovery. Sharma said operators in south Texas have reported improved initial production rates ranging from 20% to 40% using the zipper method. “I would say that this is definitely the way people are going to be doing a lot of their fractures in the future,” he said. “What I think we need to do is understand better how it works— why it works. Once we understand that, we can apply it much more efficiently.”

Production Analysis Couples Multivariate Statistical Modeling and Pattern Recognition

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 168628, ’Application of Multivariate Statistical Modeling and Geographic-Information-Systems Pattern-Recognition Analysis to Production Results in the Eagle Ford Formation of South Texas,’ by Randy F. LaFollette, SPE, Ghazal Izadi, SPE, and Ming Zhong, SPE, Baker Hughes, prepared for the 2014 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed. Approximately 5,000 horizontal Eagle Ford wells have been completed in south Texas. Still, geologists and engineers question whether their companies are using the most appropriate operating practices. Multivariate statistical analysis of larger data sets offers sound interpretation across larger geographic areas, with the provision that correlations need to be scaled to local conditions. The purpose of this paper is to apply multivariate statistical modeling in conjunction with geographic-information-systems (GIS) pattern-recognition work to the Eagle Ford. Introduction With approximately 5,000 horizontal Eagle Ford wells now completed, large sets of public and proprietary data are available for production and completion-/ stimulation-optimization studies. However, the processes of gathering data, quality control, learning what questions to ask of the data sets, and learning how to ask these questions in robust statistical fashion contain many challenges. Data sets involving large well counts contain many variables that are not ideally distributed or have missing or bad values. This work uses particular data-mining methods, particularly GIS mapping and boosted-tree regression modeling, to attempt to overcome some of the challenges with the available data sets to better understand the effect of key well, completion, and stimulation parameters on productivity and production efficiency. In this work, the Eagle Ford formation of south Texas was divided into three major producing areas that were subsequently studied with mapping techniques and that were individually modeled by use of boosted trees. Formation, Study Area, and Goals The Eagle Ford formation is a Late Cretaceous sedimentary-rock formation that underlies much of south Texas. The rocks are mainly organic-matter-rich fossiliferous marine shales of the Lower Eagle Ford interval. The play extends over an area of approximately 11 million acres overall, and the main body of the play stretches from the Texas/Mexico border to the eastern borders of Gonzales and Lavaca counties (Fig. 1). The northern part of the play (highlighted in green) is in the oil-maturation window, and, in addition to producing crude oil, it also contains lesser amounts of natural gas and natural-gas liquids (NGLs). Situated to the south and southeast of the oil window, the wet-gas region (highlighted in yellow) produces gas along with high volumes of NGLs. The southernmost region (highlighted in red) contains mostly dry natural gas. Because oil and NGLs command a higher price than natural gas, producers have mostly focused on extracting the formation’s oil and NGL resources.

Shale 2.0: From Efficient to Effective Shale Development

Guest editorial Hydrocarbons from shale were first produced commercially as long ago as 1821, and from the 1860s through the 1920s gas was produced from shallow, low-pressure, naturally fractured shales in the eastern US. However, today’s shale “revolution” did not really begin until 1985. That was when George Mitchell started developing a model for economically viable exploitation of the Barnett Shale. It took almost 20 years and literally hundreds of wells to find the right formula, based on two transformative technologies: horizontal drilling and multistage hydraulic fracturing. Shale 1.0: The Quest for Operational Efficiency Since roughly 2005—the beginning of what I call Shale 1.0—we have successfully revived old shale plays and developed new ones. Every year, North American companies complete thousands of wells in shale reservoirs. However, even in mature plays like the Barnett, where productivity per well has doubled or tripled over the past decade, as many as 30% of all perforation clusters contribute absolutely nothing to production. That is the same as drilling 30 totally nonproductive wells out of every 100. To improve shale economics, operators and oilfield service companies have focused considerable brainpower and technical resources on reducing the unit cost of production through greater operational efficiency. In many cases, we have brought drilling and completion costs down 50%, largely through application of new technologies, efficient project management, and supply chain negotiations. In some cases, advanced drilling technologies, automation, and real-time data have slashed average time to total depth from 48 days to just 8. Not all new technologies are exotic. For example, installation of rupture disk valves—which replace coiled tubing or drillpipe-conveyed perforations for the first stage in horizontal wells—reduced completion costs in 15 Eagle Ford wells by more than USD 100,000 per well. The shale revolution has yielded many economic and social benefits, including growth in jobs and local businesses across the US, lower domestic energy costs, reduced CO2 emissions, and—perhaps most important—access to a new national resource that holds enormous potential for long-term energy security. According to the Institute for Energy Research, the US has more than 200 years’ capacity of technically recoverable oil reserves and 110 years’ worth of natural gas at current rates of consumption, much of those from unconventional plays. In fact, shale oil is leading the current growth in US crude production. The US Energy Information Administration conservatively predicts global shale oil production will reach more than 4 million BOPD by 2030. Other analysts double that estimate.