Economides Consultants Inc.

Stevens Point, TX, United States

Economides Consultants Inc.

Stevens Point, TX, United States
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Asibor E.,University of Houston | Marongiu-Porcu M.,Economides Consultants Inc. | Economides M.J.,University of Houston
Journal of Natural Gas Science and Engineering | Year: 2013

Almost always oil production is accompanied by the surface production of associated gas. In the case of under-saturated reservoirs where the gas-oil-ratio (GOR) is expected to be relatively constant, the gas production rate from the field is expected to increase according to any increase in oil production rate. For saturated reservoirs the gas production rate over time increases because the solution gas-oil ratio is a function of pressure. More gas is released from the oil as the pressure drops. With the above phenomena in mind, it means that any plan to maximize reservoir oil production must be followed by a plan to handle the associated gas. In the case where gas production rate is at maximum capacity as dictated by surface facility limits, it can be inferred that oil production rate may have to be held below a certain level. If gas is "harvested" at its raw state, i.e., out of the primary separator and before it is treated, the benefits would be far more than the obvious saving of the costs from treating the gas. Compressed natural gas (CNG) en route to onshore or to a centralized LNG facility for example becomes then a tool of primary gas management. In a study performed on a theoretical reservoir and modeled after a West African deep-water field which has approximately 2 billion barrels of oil in place, twenty (20) producers, six (6) gas injectors and twelve (12) water injectors, it was determined that an additional 193.5 million barrels of oil could have been produced over ten years had there not been a limit to the gas production rate to be handled. The maximum field gas production rate per day in this study was 1060 MMSCF/d, of which 415 MMSCF/d was re-injected daily into the reservoir. The maximum field oil production rate was 250,000 STB/d and the maximum field water production rate was 80,000 STB/d. This work shows the advantages of eliminating production constraints imposed by natural gas production. With gas harvesting, the field oil rate can be optimized to ensure that the reservoir is producing at its true potential. © 2013 Elsevier B.V.

Liu T.,Texas A&M University | Marongiu-Porcu M.,Economides Consultants Inc. | Ehlig-Economides C.,Texas A&M University | Economides M.J.,University of Houston
Society of Petroleum Engineers - Kuwait International Petroleum Conference and Exhibition 2012, KIPCE 2012: People and Innovative Technologies to Unleash Challenging Hydrocarbon Resources | Year: 2012

Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration. The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding. Copyright 2012, Society of Petroleum Engineers.

Ajao O.,Economides Consultants Inc. | Iwu C.F.,Economides Consultants Inc. | Dalamarinis P.,Economides Consultants Inc. | Economides M.J.,University of Houston
Journal of Natural Gas Science and Engineering | Year: 2013

Hydraulic fracturing, which has emerged as the premier well completion technology in the petroleum industry, is applied to almost all natural gas wells, worldwide, but for different reasons. It may sound trite but all gas fields should be considered as "unconventional, compared to oil wells." In higher-permeability reservoirs (>5md) the remediation of reservoir-to-well turbulence is the main motivation. In lower-permeability reservoirs the main rationale is similar to oil- stimulation- but with significant adjustments. In much tighter reservoirs, including shales, the purpose is to inundate the formation with a very large number of parallel fractures, executed transversely from horizontal wells. This would lead to the effective draining of the Stimulated Reservoir Volume (SRV).We present here two complete field studies, one in a 17md dry gas well in Siberia, and the second from a 0.0001md shale formation in the United States. The shale formation is assumed to have a number of similar properties with the field data from the 17md gas well. The first study shows the impact of turbulence and its removal via hydraulic fracturing. We also show the management of inside-the-fracture turbulence through the adjustment of fracture geometry and the selection of higher permeability proppant. The design approach uses the Unified Fracture Design (UFD), which is the only way to adjust fracture geometry based on expected flow performances. The drainage shape and the irregular ratio between reservoir length and fracture spacing are important considerations in SRV.We also conduct a parametric study on the turbulence effects inside the fractures for a range of reservoir permeabilities. We discuss design/execution constraints which are necessary at very low or very high permeabilities.For the shale reservoir, while turbulence effects appear to be inconsequential, the length of the fracture, the spacing among fractures and the actual number of fractures are critical variables for the physical production optimization. This study evaluates these factors. © 2013 Elsevier B.V.

Marongiu-Porcu M.,Economides Consultants Inc. | Ajao O.,Economides Consultants Inc. | Dalamarinis P.,Economides Consultants Inc. | Economides M.J.,University of Houston
Society of Petroleum Engineers - SPE Asia Pacific Oil and Gas Conference and Exhibition, APOGCE 2013: Maximising the Mature, Elevating the Young | Year: 2013

The production of natural gas from coal seam reservoirs follows a succession of stages that are well established and understood. Salient components are the execution of hydraulic fractures, dewatering of both native and introduced water, and the subsequent production of what it is almost entirely methane. Most coal seams are of relatively small net pay thickness and in many cases also of low permeability, i.e. 2 md or less. Produced gas comes from a combination of both free gas in the coal porosity and, especially, desorbing gas. Because of large heterogeneities and major differences among coal seam reservoirs, the hydraulic fracturing is rarely uneventful with a large number of issues to be resolved, such as fluid selection or the mass of proppant. Most of these decisions are local and often conclusion cannot be drawn from elsewhere. Frequently, a well is subjected to multiple stages of hydraulic fracture treatments. Production performance characteristics also vary considerably. The interaction between permeability, natural cleat networks and natural and artificial fractures is often complicated and difficult to predict. This results in different periods of post-treatment de-watering, the volume of water that is produced and the onset of predominant natural gas production. We have constructed a realistic physical and economic model where the NPV criterion is used to identify successful or potentially uneconomic candidates. We forecast fractured well performance using the Unified Fracture Design (UFD) approach and we account for time of de-watering and the cost of water management. Charged against the net present value of the revenue are the costs of fracturing and well completion. Five wells with different Langmuir isotherm parameters were considered for the NPV parametric studies. The parametric studies include a range of reservoir permeabilities, porosities, proppant masses, and fracture heights. The results show the window of attractive prospects and delineate the unattractive prospects which can be considerable. Copyright 2013, Society of Petroleum Engineers.

Wang H.Y.,University of Houston | Marongiu-Porcu M.,Economides Consultants Inc. | Economides M.J.,University of Houston
SPE Production and Operations | Year: 2016

The prevailing approach for hydraulic-fracture modeling relies on linear-elastic fracture mechanics (LEFM). Generally, LEFM that uses stress-intensity factor at the fracture tip gives reasonable predictions for hard-rock hydraulic-fracturing processes, but often fails to give accurate predictions of fracture geometry and propagation pressure in formations that can undergo plastic failures, such as poorly consolidated/unconsolidated sands and ductile shales. This is because the fracture-process zone ahead of the crack tip, elasto-plastic material behavior, and strong coupling between flow and stress cannot be neglected in these formations. Recent laboratory testing has revealed that in many cases, fracture-propagation conditions cannot be described by traditional LEFM models. Rather, fractures develop in cohesive zones. In this study, we developed a fully coupled poroelasto- plastic hydraulic-fracturing model by combining the cohesivezone method with the Mohr-Coulomb theory of plasticity, which not only can model fracture initiation and growth while considering process- zone effects, but also can capture the effects of plastic deformation in the bulk formation. The impact of the formation plastic properties on the fracture process is investigated, and the results are compared with existing models. In addition, the effects of different parameters on fracture propagation in ductile formations are also investigated through parametric study. The results indicate that plastic and highly deforming formations exhibit greater breakdown and propagation pressure. The more plastic the formation (lower cohesion strength), the higher the net pressure required to propagate the fracture. Also, lower cohesion strength leads to shorter and wider fracture geometry. The effect of formation plasticity on a hydraulic fracture is mostly controlled by initial stress contrast, cohesion strength of formation rock, and pore pressure. We also found that altering the effective fracture toughness can only partially mimic the consequences of increased toughness ahead of the fracture tip in ductile formations, but it fails to capture the effect of shear failure within the entire affected area, which can lead to underestimating the fracture width and overestimating the fracture length. For a more-accuratemodeling of fracturing in ductile formations, the entire plastic-deformation region induced by the propagating fracture should be considered, especially when shear-failure areas are large. Copyright © 2016 Society of Petroleum Engineers.

Li D.,Sinopec | Dalamarinis P.,Economides Consultants Inc. | Economides M.J.,University of Houston
Society of Petroleum Engineers - SPE Canadian Unconventional Resources Conference 2013 - Unconventional Becoming Conventional: Lessons Learned and New Innovations | Year: 2013

Hydraulic fracturing, which has had a long and well established place in petroleum production engineering, especially in the mature areas of North America, has emerged recently with equally large role to play in China. Tight reservoirs including shale gas have promoted Chinese fracturing activities to ever higher levels. Western design and execution techniques have been adopted and modified. We present field examples for the Shun 9, a low-permeability oil reservoir (permeability ranges from 0.001 to 0.1 md) in North-Western China for which horizontal wells with multiple fractures appear to be the only choice for some credible production. The physical optimization in this work is done with the Unified Fracture Design (UFD), partitioning the well length and employing a large number of fractures. Design of each fracture is treated separately with an allocated drainage area allowing different aspects ratios in each iteration of design. The UFD approach is augmented by a net present value (NPV) calculation allowing for the critical economic optimization. In past work NPV has been a decisive element in the optimization process, because it utilizes operational costs and hydrocarbon production to evaluate reservoirs which are candidates for exploitation strategies. The number of fractures per well, their spacing and the size of the fractures are the results of this optimization. Actual treatment variables are presented, including all injection variables, fluid and proppant properties. Based on post-treatment well performance, the entire project presented here is marginal when considering economics e.g., the best is a 5-year NPV of $5 million for a horizontal well with four-transverse fractures. A comprehensive approach is required for this reservoir, optimizing well architecture and costs. What we present in this paper is the procedure to achieve the best physical optimization, followed by the proof of economic viability through the NPV calculation. Copyright 2013, Society of Petroleum Engineers.

Marongiu-Porcu M.,Economides Consultants Inc. | Economides M.J.,University of Houston | Holditch S.A.,Texas A&M University
Journal of Natural Gas Science and Engineering | Year: 2013

Optimization has taken several different hues in all areas of engineering. Hydraulic fracturing, as applied to oil and gas wells, has had its share. In the past, and before the maturing of high-permeability fracturing and the tip screen out techniques, this well stimulation procedure was limited to low-permeability reservoirs and unrestricted fracturing. In such cases, the fracture length would be an appropriate design optimization variable against an economic criterion, e.g., the Net Present Value (NPV). This involved the balancing of incremental future revenue against the cost of execution. Also interesting would be parametric studies, allowing the variation of execution variables and the detection of differences in their respective design NPV. Such differences would be useful in decisions to measure a variable or stay within reasonable assumptions. The emergence of higher-permeability fracturing and the Unified Fracture Design (UFD) concept allowed two important notions. First, there is no difference between low and high-permeability reservoirs in terms of benefiting from fracturing. Just execution issues need to be resolved. Second, and more important, for any mass of proppant to be injected in any well, there exists only one fracture geometry that would maximize production. This geometry, consisting of length and propped width (with height as a parasitic variable) can be readily determined and, if placed, it will provide the maximum productivity index. All other combinations of length and width would result in lower productivity values. This is physical optimization.In this paper we combine the two: the economic and physical optimizations. For each proppant mass we first optimize the fracture physical performance, and then we apply the NPV criterion. We perform a series of parametric studies for a range of gas reservoirs and we use economic variables that differ in various parts of the world. We show how to determine the optimum fracture size. We then show how fracture treatments may be attractive in certain reservoirs in mature areas but not attractive elsewhere. We also show that for a diversified company, given the choice, few successful fractures in high-permeability reservoirs are far preferable to fracturing large numbers of wells in lower permeability fields, although the latter can be made economically attractive only through hydraulic fracturing. © 2013 Elsevier B.V.

Pitakbunkate T.,Economides Consultants Inc. | Yang M.,Texas A&M University | Valko P.P.,Texas A&M University | Economides M.J.,University of Houston
SPE Production and Operations Symposium, Proceedings | Year: 2011

In 2002 we introduced the concept of Unified Fracture Design (UFD) as a coherent way to size the fracture geometry for the expressed purpose to physically optimize the well performance. We used the Proppant Number as a correlating parameter, which in turn provided the maximum dimensionless productivity index (JD) which corresponds to the optimum dimensionless fracture conductivity, CfD. Once the latter is determined, the fracture dimensions, i.e., fracture length and width, are set. If one assumes the fracture height is known and constant then the calculation is simple and a 2D fracture propagation model can be used. However, fracture height is not constant throughout the fracture and it cannot be considered constant during execution, depending greatly on the net pressure and vice versa. We are presenting here an iterative procedure where the fracture height is related to the net pressure. In the procedure, for any assumed net pressure, the fracture height, along with the mass of proppant and the permeabilities of the reservoir and the proppant, lead to the Proppant Number which in turn determines the desired length and width. A fracture propagation model, such as the PKN geometry for lateral growth, coupled with a changing fracture height, leads to the calculation of the net pressure which is compared with the one assumed. Convergence of the assumed and calculated net pressure is what is sought. The design procedure presented here is for both oil and gas wells. The design also includes the calculation of required treating pressure and finally it incorporates economics for production enhancement optimization beyond the physical optimization using UFD. Comparison of the 2D to the p-3D results points to the need and importance of the p-3D in a large array of reservoirs. Copyright 2011, Society of Petroleum Engineers.

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