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.
Long-term zonal isolation provided by cement is a crucial task in the life of oil and gas wells. However, significant number of primary cementing jobs experience problems, particularly in highly deviated wells, extended reach wells, and wells prone to severe washouts. Primary cementing efficiency has attracted more attention since the development of shale gas industry and the Macondo blowout in the Gulf of Mexico. Sustained casing pressure reported in some of the wells in Marcellus shale play and the root of several blowouts is attributed to the quality of cement job. Therefore, studies on the performance of cementing operations are essential in restoring the public opinion on petroleum industry by addressing problems that have major social, environmental and economical consequences besides the technical interest.
Casing is prone to deviate toward the bottom of the well especially in horizontal wells. This eccentric annular space leads to annular velocity disturbance in favor of wider region of the annulus. Finally, part of the narrow section of annulus would be left un-cemented. The bypassed mud is a potential path for the formation fluid communication with other formations or to the surface. Poor cementing can affect the hydraulic fracturing job as well.
This paper reports on a comprehensive three-dimensional time-dependent computational fluid dynamics (CFD) model developed to account for dominant parameters affecting the mud displacement process in horizontal wells. Parameters such as casing eccentricity, cement yield strength, cement plastic viscosity, the density difference between mud and cement, pumping rate and washout are studied. The effects of the first three parameters are addressed in this paper.
Current best cementing practices have deficiencies in providing excellent cementing efficiency. Therefore, a novel technique, using Magneto-Rheological (MR) fluid, is also proposed to improve the displacement efficiency. MR fluid can act as a plug in the wider region of annulus under a magnetic field applied through the casing. Consequently, flow will be directed to the narrower annular region that could not be cemented or cleaned otherwise. The results are appealing and further study on the application of MR fluid in petroleum industry is suggested.
Shale gas reservoirs are quickly becoming an important source for natural gas. Historically, the shale basins were not looked at for economic production because of their very low permeability values. However, with the use of hydraulic fracturing combined with horizontal well completions, shale plays have become economically producible, especially the Marcellus shale. In order for these wells to produce, hydraulic fracturing must be employed. This technique makes production viable, but it also changes the in-situ stress field, through the fracture itself and the increased production that occurs. This change in the stress field can damage the wellbore and compromise the integrity of the casing.
In this study, geomechanic and reservoir models were constructed using commercially available software to study the change of the stress field in the formation. The parameters of the hydraulic fracture were varied to study the effects of the hydraulic fracture half length and the fracture permeability on the stress field, specifically near the wellbore.
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.
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.
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.
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 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.
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.