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Results
Abstract Borehole acoustic tools that use broadband source excitation functions can optimally excite multiple frequencies at nearly the same time, yielding a wide range of different formation acoustic response properties in the received signal. However, the analysis of received broadband signals is not straightforward in the time-domain because standard time semblance algorithms suffer from interference when received acoustic modes with different slownesses and frequency content arrive at a similar time. Another method, frequency semblance, is computationally expensive and is sensitive to noise and to other effects. We propose using specially designed phase filters that can move (delay) individual frequency contributions differently in time without changing the spectral amplitudes of the received signal, thus enabling existing time semblance methods to perform optimally at many frequencies by separating the received spectra in time.
Abstract Accurate quantification of total organic carbon (TOC) is an important step in evaluating log data in organic-rich reservoirs. The literature describes many log-based approaches for predicting TOC that have been introduced over the years, including the use of uranium content or GR linear regression, bulk density, the DeltaLogR approach, neural network approach, and a response equation-based method using sonic, density, and resistivity logs. All of the approaches require core-to-log calibration for validation. Each of these techniques involves assumptions for them to be valid, and, in a given instance, it is possible some techniques will not produce reliable results. However, good log-based TOC quantifications can be achieved by taking the median average of TOC estimates from several indicators. Many shale reservoirs contain 10 wt% pyrite and total organic carbon (TOC), which translates to 7% pyrite and 20% kerogen by volume. High volumetric percentages of pyrite and kerogen significantly affect the rock grain density. In low-porosity shale reservoirs, each 0.02 g/cm error in grain density produces approximately 1 p.u. error in porosity. Pyrite is commonly present in organic-rich shale intervals of shale gas formations because of the reducing conditions that enhanced organic matter preservation, and it may play a role in decreased resistivity response if the volume is sufficient. Consequently, in shale reservoirs, any method of predicting TOC using resistivity logs, such as DeltaLogR, should also consider the presence of pyrite. Similarly, TOC predictions based on bulk-density logs may also be sensitive to elevated pyrite concentrations. The link between pyrite presence and the depositional environment for many organic-rich shale reservoirs suggests that pyrite and sulfur may be useful TOC indicators in some situations. This paper examines the possible application of pyrite and sulfur for predicting TOC in shale reservoirs, such as in the Haynesville shale reservoir, but results should be applicable to many other shale reservoirs. An interesting result is that, although it may be possible to calibrate a TOC-based pyrite indicator for individual wells, the calibration is not universally applicable.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Sulfide > Iron Sulfide > Pyrite (1.00)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
Abstract 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.
- North America > United States > West Virginia (1.00)
- North America > United States > Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin (0.99)
- (14 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract 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 wellboreโs 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.
- Research Report > New Finding (0.48)
- Overview > Innovation (0.34)
Abstract A testing methodology was developed to examine the effectiveness of oil-swellable additives in cement slurries by evaluating the capability to shut off hydrocarbon fluid flow through a crack initiated in the cement. An open-loop testing fixture was used to investigate the effect of oil-swellable additive concentration and environmental temperature, using Kaydol mineral oil as a test fluid. Under a pressure differential of approximately 2 psi/in., test results indicated that a concentration of 10% by volume of additive relative to a 15.5 lbm/gal Class G slurry was sufficient to significantly reduce hydrocarbon flow in a crack in cement at a temperature of 160ยฐF in an average time span of 48 hr and in shorter time spans with an increase in temperature.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.42)
Abstract Recent interest in the development of Marcellus and Utica plays has renewed attention on the problem of reliable estimation of recoverable reserves from low-permeability shale gas formations. Over-optimistic results obtained from the commonly used Arps hyperbolic model has led to the development of alternative decline curve analysis models based on empirical considerations (e.g., Duong's power law model) or mechanistic considerations (e.g., Valko's SEDM). This work addresses the practical difficulty of discriminating between such models (including a new mechanistic model proposed for decline curve analysis based on the Weibull growth curve) from limited production data. The paper also presents a new approach to aggregating estimated ultimate recovery (EUR) forecasts from multiple plausible models using the Generalized Likelihood Uncertainty Estimation (GLUE) methodology. Two field examples are presented to demonstrate the performance of Hyperbolic, SEDM, Duong and Weibull models. Model parameters are estimated via nonlinear regression using Excel-SOLVER, from which 30-year EUR estimates are generated. The GLUE procedure is then used for determining the likelihood of each model by weighting the results with [1/RMSE^2], and computing the weighted mean and standard deviation for the 30-year EUR. For the first example (with 15 years of data), excellent visual fits are obtained for both rate and cumulative production with all four models. However, 30-year EUR estimates from the Arps and Duong models are on the high side and the SEDM and Weibull models are on the low side. The uncertainty in the mean amounts to only ~2%. For the second example (with 52 months of data), the trends are very similar, albeit with greater separation in the 30-year EUR forecasts and a higher uncertainty in the mean EUR (~7%). These results reinforce earlier findings that multiple alternative models can provide equally good fits to limited-duration production data, but yield very different 30-year EUR forecasts. The GLUE approach provides a robust methodology for aggregating such analyses and quantifying the uncertainty of the EUR forecast.
- Research Report > New Finding (0.66)
- Overview > Innovation (0.60)
- Research Report > Experimental Study (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.62)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract 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 cementing job performance. 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 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 is part of 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 fluid, is also proposed to improve the displacement efficiency. Magneto-Rheological fluid can act as a plug in the wider region of annulus under 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 application of Magneto-Rheological fluid in petroleum industry is suggested.
- North America > United States > Virginia (0.34)
- North America > United States > West Virginia (0.34)
- North America > United States > New York (0.34)
- (3 more...)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)