A method of using surface acquired radiation data has proven successful in Kentucky's shallow oil reservoirs of the southern Illinois Basin. The theory adhered to is that measured surface radiation shows characteristic low activity above petroleum deposits when compared to surrounding areas. Mapping measured potassium data layered with total radiation data can aid in identifying pooled hydrocarbon deposits as well as the area and extent of these deposits.
An overview of proper field acquisition operations is given as well as an analysis of three radiometric surveys taken in Kentucky.
The benefits of a new class of a multifunctional cement additive and the performance of the resulting cementing systems are evaluated in comparison to conventional slurry designs used for cementing wells in the Northeastern U.S. Cement testing procedures, lab test results, logistical and operational aspects, economical and ecological balances, chemical footprints of slurry designs are presented and discussed. The tested multifunctional additive can fully replace at least 4 different additives
(extender, suspending agent, free fluid, fluid loss, and gas control additive) to achieve the desired performances and so simplify cement slurry designs. The multifunctional additive in this study also exhibits delayed hydration, which facilitates surface mixing and generates desired high viscosity over time, minimizing settling issues in horizontal wells during placement. The innovative cement design concept using a multifunctional additive reduce the number and loadings of chemical additives required to adjust the performance of cement slurries, thereby improving economics, reducing the chemical footprint, and simplifying logistics and operations.
EQT Production has been actively drilling the Marcellus Shale in Pennsylvania and West Virginia since 2008. With over 170 producing horizontal wells in the Marcellus, EQT has a significant data set for evaluation using Multiple Linear Regression. A variety of well design parameters can be compared to production in hopes of finding a correlation and identifying what determines a well's Estimated Ultimate Recovery (EUR). Some of the most logical parameters to compare include lateral length, lateral azimuth, formation target, formation mineralology and stimulation design. Multiple Linear Regression is a powerful tool for bringing many of these design aspects together for comparison against productivity and can reveal patterns and relationships that may be indiscernible using conventional methods.
A regression software package was used for this study following the Least Squares method. Well EUR was the primary dependent variable throughout the analysis. Each individual dataset consists of wells in close proximity to one another (map quad, county, etc.). Dozens of drilling and completion parameters were compared against the EURs, as independent variables. Multiple iterations of removing and adding specific independent variables led to an optimal EUR model for a particular area.
Four main areas were the focus for the study, and the results have been conclusive. In all areas, treated lateral length exhibited a near-linear relationship with EUR. More specifically, in Area 1, the model exhibited an R-Squared value of 0.97. This was achieved using only three independent variables: treated lateral length, perforation cluster spacing, and lateral spacing. Realistic models were built, with conclusive results, in Areas 2, 3, and 4 using different criteria.
Multiple Linear Regression Models can provide extremely important information for field development. Using MLR models, coefficients are obtained for each of the independent variables (i.e. the quantitative effect each parameter has on a well's EUR). These values can be extended to new areas, and a more accurate EUR can be predicted, often before the well is drilled. In core areas, when an operator is forced to make decisions based on land and drilling constraints, this method can be used to make the best economic decision for drilling and completion design.
Proppants are essential to the success of most hydraulic fractures and often account for the overwhelming cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are important elements in gaining the highest Net Present Value (NPV).
It has been generally believed that in the lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. A commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environments, invariably, deeper reservoirs.
The characteristics of most shale plays are very different, mainly as regards to the rock stiffness, exemplified by the Young's Modulus, stress anisotropy/isotropy and the existence of natural fracture network. Fracture strategies in shale formations are very different. This study presents fracture designs based on three types of proppants for shale formations: Brady sand, Ottawa sand and ceramic. Permeability tests and crush tests under certain pressure range are done to determine experimentally the dimensioned fracture conductivity. A fracture optimization p-3D model is used to maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered for gas reservoirs. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production over the well life. NPV analysis is employed as the criterion to select the best proppant for the job. Finally, the completion and production data from example wells will be analyzed for comparison purpose.
In this work, we try to correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. Keeping stimulation costs down, natural sands proppants have a much larger range of applicability than previously thought.
Most unconventional gas reservoirs are naturally fractured in nature and exhibit dual porosity characteristics. Hydraulic fracturing often alters the reservoir parameters around the wellbore, thus, potentially creating a rubble zone (stimulated reservoir volume-SRV) with distinctly different characteristics when compared to the outer zone. This problem could ideally be approximated as an equivalent flow problem around a horizontal wellbore in a composite naturally fractured domain.
The computational package developed in the current study could be used in generating forward solutions for prediction of production transients in hydraulically fractured double porosity reservoirs. Additionally, as a part of an inverse analysis procedure, using relevant dimensionless parameters, it will be possible to characterize the composite naturally fractured reservoirs.
A solution to the elliptical flow problem that considers flow into a horizontal wellbore in a truly composite naturally fractured reservoir is attempted. Mathieu modified functions are used to solve the elliptical flow problem. Stehfest algorithm is used for inversion of the Laplace space solutions back to real time domain. This generated solution is validated with other existing solutions by collapsing it into its subsets given in the literature. Forward solutions are generated for various dimensionless parameters. A graphic user interface (GUI) is developed to generate production decline curves.
The interface elliptical coordinate does have a significant effect on the dual porosity signature of production transients in the case of mobility ratios higher than 10. It is observed that the mobility ratio, diffusivity ratio, storativity ratio, interporosity flow coefficient ratios of the inner, and outer regions exhibit significant effects on the decline curves experienced by this class of reservoirs.
Closed perforations and damaged sections are two great challenges in the petroleum industry. Several reasons may cause these problems. Few of them depend on the type of formation and wellbore while others come from drilling, completion and stimulation activates before production process. Production rate and pressure drop may lead significantly to these two problems; therefore, production management sometimes plays great role in controlling them. Millions of dollars are spent annually for the remedial process of these two problems. Therefore the prediction of them is considered of great importance as an attempt to control them or reduce their negative impact on wellbore deliverability.
This paper introduces a new technique to predict closed perforations and damaged sections problems using pressure transient analysis. Pressure behaviors and flow regimes in the vicinity of horizontal wellbores are affected by the existence of the closed perforated zones and the formation sections where the resistance to reservoir fluid flow toward the wellbore is maximized. This resistance occurs because of the damaged permeability and high skin factor. Analytical models for predicting these problems and determining how many zones of the horizontal well that are considerably affected by them have been introduced in this study. These models have been derived based on the assumption that wellbore can be divided into multi-subsequent segments of producing and non-producing intervals. Producing intervals represent free flowing zones where there is no problem and both formation and wellbore are assumed to be clean. Non-producing intervals represent zones where both formation and wellbore's perforations are closed or damaged.
The effective length of horizontal well where the perforated zones and the formation sections can not be considered problematic and the damaged length where both of them are significantly closed and damaged can be calculated. The numbers of the damaged zones can be calculated also. In addition, the locations of the damaged sections or closed perforated zones can be determined. Type-curve matching technique and the analytical models can be used for this purpose.
New and unconventional reserves are now being developed in more isolated and remote locations by drilling extended-reach horizontal wells (ERWs). The complexity of designing tubulars for ERHWs depends on the well objectives, target's location and wellbore trajectory. Tubular design must be compatible with the intended wellbore trajectory to minimize the downhole dynamic events such as torque and drag, buckling and vibrations. The existing dynamic models for calculating anticipated axial load and torque distribution for tubulars in ERHWs consider only the effect of the normal contact loads and frictional forces. However, lateral and torsional vibrations are critical to the tubular design for ERHWs because vibrations contribute to the total normal contact load. This study uses the unbalanced force and fluid added mass theories to quantify the magnitude of the normal contact load generated during lateral vibrations of a near-straight tubular section in an ERHW. The generalized model is developed using the knowledge of engineering mechanics to integrate axial load, torque, buckling and vibrations models. The integrated dynamic equations neglect the hydraulic effects in drilling tubulars and weight-on-bit term in completion tubulars. It was observed that the downhole dynamic events contribute a relatively higher percentage to torque transfer than they do to axial load transfer. Also, when all the downhole dynamic events occur together and the critical buckling loads have not been reached, torque and drag events contributes the major portion of the axial load transfer followed by lateral vibrations. The model equations developed in this paper are validated using the well data from one of the world's longest ERHWs. The calculation of axial load and torque distribution accounts for the underestimated values of loads and torque obtained from previous dynamic models. This study will lead to better drilling optimization through the minimization of failures, non-productive times, and ultimately reduced total drilling costs.
The Marcellus Shale play has attracted much attention in recent years. Our full understanding of the complexities of the flow mechanism in matrix, sorption process and flow behavior in complex fracture system (natural and hydraulic) still has a long way to go in this prolific and hydrocarbon rich formation.
In this paper, we present and discuss a novel approach to modeling and history matching of hydrocarbon production from a Marcellus shale asset in southwestern Pennsylvania using advanced data mining & pattern recognition technologies. In this new approach instead of imposing our understanding of the flow mechanism, the impact of multi-stage hydraulic fractures, and the production process on the reservoir model, we allow the production history, well log, and hydraulic fracturing data to force their will on our model and determine its behavior. The uniqueness of this technique is that it incorporates the so-called "hard data?? directly into the reservoir model, such that the model can be used to optimize the hydraulic fracture process. The "hard data?? refers to field measurements during the hydraulic fracturing process such as fluid and proppant type and amount, injection pressure and rate as well as proppant concentration.
The study focuses on part of Marcellus shale including 135 wells with multiple pads, different landing targets, well length and reservoir properties. The full-field history matching process was completed successfully. Artificial Intelligence (AI)-based model proved its capability in capturing the production behavior with acceptable accuracy for individual wells and for the entire field.
This study develops a process that determines the critical hydraulic fracture parameters and quantifies their impact on the EUR by combining reservoir simulation with probabilistic analysis methods. The process is verified by a real field case example in a tight gas reservoir. The final product can be applied to other unconventional reservoirs to ultimately maximize revenues by planning superior fracturing operations and optimizing well spacing.
A detailed dual porosity, 1 section reservoir model was created and history matched to model the flow mechanism. A fine layered (2-3ft) geostatistical model was utilized in simulation without upscaling. The dual porosity formulation enabled the simulation model to represent the hydraulic fracture - matrix interaction properly so that the flowback and formation water production could be matched also.
During the history matching phase, the parameters that control the impact of hydraulic fractures on the recovery were identified as follows:
In this work, an internal proprietary technology that creates a response surface for the combination of the parameters defined above was utilized. This technology utilizes Experimental Design, Response Surfaces and Constrained Monte Carlo. The history matched simulation model was automatically modified to create the necessary cases to calculate a multi-dimensional response surface. The created response surface was then used to do Monte Carlo simulations to create P10 to P90 probabilities of the total gas production (EUR).
The results of the study allowed us to understand not only the mechanisms operating in the reservoir being studied, but also the required hydraulic fracture parameters (ranges) to achieve a given EUR of a specific probability. The same algorithms were then be used to predict the future performance of other well spacing patterns and hydraulic fracture job sizes.
To date the most prolifically producing geologic structure in Montana's Bakken formation is the Elm Coulee Field. While the first wells drilled into this structure 35 years ago had some success, significant production did not occur until horizontal wells were drilled starting in 2000. The Bakken Petroleum System consists of three members, the Upper Bakken, shale, the Middle Bakken, silty dolostone, and the lower Bakken, siltstone. Production of the Bakken Petroleum System is extremely difficult to predict with standard reservoir models. Thus, the decision to understand initial production through geologic drivers was made. An investigation of the implications of ancient geology on what is believed to be specific areas of micro-flexures in and around the major geologic structures in Montana's Bakken three-member formation will form the basis for a Bakken production model.
The challenge in modeling the Bakken's production, both initial and subsequent, stems from the unusual history matching problem of either extremely high initial production with an unpredictably low subsequent production or surprisingly low production to begin with. The authors believe this phenomenon is due to broaching a series of micro-flexures and draining them, resulting in high initial production and unsustained subsequent production, or missing these structural flexures all together resulting in low production. This paper will investigate the genesis of Montana's Bakken micro and macro fractures with the ultimate goal of simulating and thus predicting production for wells currently producing in the area.