In the 1970s, the United States government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate. Eq. 7.1 clearly shows that the flow rate, q, is a function of permeability k; net pay thickness h; average reservoir pressure p; flowing pressure pwf; fluid properties β μ drainage area re; wellbore radius rw; and skin factor s. Thus, to choose a single value of permeability to define "tight ...
Tight gas reservoirs generate many difficult problems for geologists, engineers, and managers. Cumulative gas recovery (thus income) per well is limited because of low gas flow rates and low recovery efficiencies when compared to most high permeability wells. To make a marginal well into a commercial well, the engineer must increase the recovery efficiency by using optimal completion techniques and decrease the costs required to drill, complete, stimulate, and operate a tight gas well. To minimize the costs of drilling and completion, many managers want to reduce the amount of money spent to log wells and totally eliminate money spent on extras such as well testing. However, in these low-permeability layered systems, the engineers and geologists often need more data than is required to analyze high permeability reservoirs.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft. The low gradients are attributable to low permeabilities, low recharge rates along the southern rim of the basin, and hydraulic isolation from the fairway area.
If least-squares linear regression is used to compute N in Step 5, an equation analogous to Eq. 17 is used (where Eow is substituted for Eowf). This solution method is iterative because the material-balance error must be minimized. This calculation is carried out with a trial-and-error method or a minimization algorithm. Least-squares linear regression and minimization algorithms have become standard features in commercial spreadsheets.
The most reliable way to determine stress orientation is to identify features (either geological features or wellbore failures) the orientation of which is controlled by the orientations of the present-day in-situ stresses. Other methods that rely on observing the effect of stress on rock properties using oriented core have been found to be less reliable and subject to influence by factors other than in-situ stress. As previously discussed, wellbore breakouts occur in vertical wells at the azimuth of SHmin, and drilling-induced tensile failures occur 90 to breakouts at the azimuth of SHmax. Therefore, the orientations of these stress-induced wellbore failures uniquely define the orientations of the far-field horizontal stresses when using data from vertical wells. This is true for breakouts whether they are detected using 4-arm- or 6-arm-oriented caliper logs or using electrical or acoustic images, whether obtained by wireline or logging while drilling (LWD) tools.
Tian, Changbing (Research Institute of Petroleum Exploration and Development, PetroChina) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Jiang, Qingping (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Chang, Tianquan (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Chen, Dongliang (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Lu, Zhiyuan (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Li, Sheng (Exploration and Development Research Institute of Xinjiang Oilfield Company)
Large platforms, long horizontal sections, small well spacings and dense cutting have become economical and effective development means for tight oil reservoirs. Well spacing and fracture design are critical parameters impacting production and Internal rate of return (IRR) of tight oil reservoirs. In order to maximize the total stimulated reservoir area and fracture-controlled reserves, the well spacing and fracture spacing should be small enough. However, in order to minimize the chance of fracture hits caused by offset wells and the overlapping drainage area of a nearby well to avoid Asset spillover, the spacing well should large enough.
Based on minifrac data and microseismic fracture mapping results, a natural/hydraulic fracture network was generated and input into an unstructured-grid-based discrete fracture reservoir simulation model. Its accuracy was calibrated with the well production history. For each group of fracture design and well spacing, well interference was determined by estimating ultimate recovery (EUR) difference between a single well and a middle well among multiple wells. Based on actual information of tight oil developments, the pressure interference were examined by field trail data and well spacing simulations. The real scenarios were selected to study effects of well spacing on EUR and ultimate IRR. Effects of reservoir permeability and fracture half-length on optimal well spacing were also analyzed.
It was found that the decrease in Long-term EURs for different well spacings is a good indicator for well spacing optimization. Based on the reservoir simulation and economic analysis, the maximum IRR of the tight oil reservoir with permeability of 0.23mD can achieved when the well spacing is 260m. Meanwhile, the detailed results were also illustrated to show the effects of fracture half-length, reservoir permeability as well as oil price variation on IRR.
The paper demonstrates an effective method and a workflow to optimize well spacing and fracture treatments design through integrating advanced multi-stage fracture modeling with discrete fracture reservoir simulation in the area of unconventional resource developments. Such optimization studies contribute to minimize operation cost and improve the economy of resource development.
In this paper we present our results, challenges and learnings, over a two-year period wherein robust multiobjective optimization was applied at the Mariner asset which is being currently developed. Many different problems were solved with different objectives. These problems were formulated based on the phases of planning and development at the asset. The optimization problems include drilling order and well trajectory optimization as the main objectives with reduction in water cut and reduction of gas production to minimize flaring as secondary objectives. We use the efficient stochastic gradient technique, StoSAG, to achieve optimization incorporating geological and petrophysical uncertainty. For some problems computational limitations introduced challenges while for other problems operational constraints introduced challenges for the optimization. Depending on the problems significant increases between 5% and 20% in the expected value of the objective function were achieved. For the multi-objective optimization cases we show that nontrivial optimal strategies are obtained which significantly reduce (40% decrease) gas production with minimal loss (less than 1%) in the economic objective. Our results illustrate the importance of flexible optimizations workflows to achieve results of significant practical value at different stages of the planning and development cycle at an operational asset.
Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.
This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.
This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.
The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.
A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible
Coupled reservoir flow and geomechanics has numerous important applications in the oil & gas industry, such as land subsidence, hydraulic fracturing, fault reaction and hydrocarbon recovery etc. High fidelity numerical schemes and multiphysics models must be coupled in order to simulate these processes and their interactions accurately and efficiently. Specifically, in the applications of CO2 sequestration, the effect of geomechanics on carbon storage estimation is not negligible. However, coupled flow-geomechanics simulations are very computationally expensive and most of the computational time is usually spent for geomechanics calculations. This paper investigates a three-way coupling algorithm that uses an error indicator to determine when displacement must be updated and whether fixed-stress iterative coupling technique is required. Numerical experiments with coupled nonlinear single-phase flow and linear poromechanics shows that the three-way coupling algorithm can speed up 4 times comparing to fixed-stress iterative coupling algorithm. Extensions to coupled compositional flow with poromechanics also shows a speed-up for 5 times for continuous CO2 sequestration applications and 2 times for surfactant-alternating-gas applications (SAG). The substantial speed up makes the three-way coupling algorithm of flow and geomechanics feasible in the large-scale optimizations. Based on the three-way coupling of compositional flow and geomechanics, we experimented two black box optimization algorithms, covariance-matrix adaptation evolution strategy (CMA-ES) and genetic algorithm (GA), for the optimization of well controls during SAG process to maximize CO2 storage volume. CMA-ES outperforms GA in that it is more robust, and it achieves higher objective function value in less simulation runs. The optimized SAG process achieves 27.55% more CO2 storage volume and reduces water and surfactant consumption by 54.84%.
Chen, Zhiming (State Key Laboraory of Petroleum Resources and Prospecting, China University of Petroleum at Beijing) | Xie, Jianyong (Xinjiang Oilfield Corporation, PetroChina) | Liao, Xinwei (State Key Laboraory of Petroleum Resources and Prospecting, China University of Petroleum at Beijing) | Li, Xiaofeng (Changqing Oilfield Corporation, PetroChina) | Zhang, Jiali (State Key Laboraory of Petroleum Resources and Prospecting, China University of Petroleum at Beijing) | Li, Rongtao (State Key Laboraory of Petroleum Resources and Prospecting, China University of Petroleum at Beijing) | Li, Lang (Liaohe Oilfield Corporation, PetroChina)
In this study, we develop a new model for the complex fracture geometries with fracture hits using an efficient semi-analytical model. The semi-analytical model has the capability to simulate shale well performance by considering complex non-planar hydraulic fractures and fracture hits. By combining nodal analysis and Laplace transforms, the pressure transient solution of the diffusivity equation is obtained. The semi-analytical model is verified against the numerical models. Then, we apply the model to analyze pressure testing data of a parent well and a child well. Results show that the flow regimes of complex fracture geometries with fracture hits include wellbore storage, skin effect, fracture bilinear flow, "fluid feed", pseudo-boundary dominated flow, unconnected fracture (UF) impact, and pseudo radial flow. During the flow regime of UF impact, the pressure derivative curves exist a second "V-shape", as the UF improve the matrix permeability and the pressure depletion will be reduce once the flow reaches the UF. Those flow regimes provide good guidelines for identification of complex fracture networks with fracture hits.