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.
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
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.
Rasoanaivo, Ombana (TOTAL S.A.) | Danquigny, Jacques (TOTAL S.A.) | Henry, Pierre (Petroleum Experts) | Hopkinson, David (Petroleum Experts) | Liu, Adeline (TOTAL E&P) | Marty, Jacques (TOTAL S.A.) | Marmier, Rémy (TOTAL E&P)
Using a software integrator, a commercial reservoir simulator is tightly coupled with a commercial Transient Well Model. This is required when transient reservoir behaviour interacts with transient wellbore phenomena. It is the case in a tight gas field which is being developed since 2012 in China; long natural cycles of gas production in liquid loading regime followed by period of low or quasi nil-gas production are observed. Cyclic production is also being implemented to optimize the average gas production. In both cases, usual decline curve analysis is no longer valid. And computing long term production forecast becomes a challenge. The innovative application presented in this paper is an optimization of Cyclic Production in Liquid Loading Regime of a tight gas reservoir by coupling transient modelling of reservoir and wellbore.
A workflow is implemented in the software integrator RESOLVE which enables the coupling between a well and its multiple hydraulically fractured reservoirs. It ensures consistent results between the reservoir model and the transient well model in terms of mass flow rate, transient inflow performance and bottom hole flowing pressure. It also enables to visualize the cross-flow which occurs between the two reservoirs, and some water imbibition into the matrix during shut-in periods.
Tested on various reference wells, this new methodology represents properly the historical behaviour of the wells during steady-state flow and during self-killing periods. When modelling cyclic production, various shut-in / restart criteria can be handled by the workflow. It enables to optimize the average production of the wells and deliver some guidelines to the field operation teams. This is a great achievement compared with the need to implement long "cyclic production testing" campaigns.
Also, two-month coupled cyclic production modelling is performed at regular yearly intervals. Combining these long term production forecasts with the evolution of "average static pressure vs. cumulative gas production" derived from reservoir standalone long-term forecast, enables to compute reliable long term production forecast which accounts for cyclic production in liquid loading regime. The current results show significantly larger production than the one derived from usual decline curves.
Overall, the study is a leap forward in understanding transient well and reservoir interactions in order to improve field Estimated Ultimate Recovery. This field tested methodology can also be applied to many other situations when well instabilities interfere with reservoir transient behaviour (gas-lift heading, interference between unstable outflow and multi-layers inflow behaviour). To our knowledge, it is a "World First" of a coupling between a full commercial reservoir simulator and a commercial transient wellbore software.
The Barik Deep clastic gas reservoir was discovered in 1991 and has been on production since 1994. It is a very rich gas condensate reservoir with initial Condensate to Gas Ratio (CGR) of 1100 m3/MMm3. With reservoir pressure dropping below dew point (428 bar vs. initial pressure of 478 bar), a huge volume of condensate has dropped-out inside the reservoir as confirmed by production data and the deterioration of well performance. As of 1/1/2018, the Barik Deep reservoir is developed with 29 gas producers out of which 7 wells are closed-in mainly due to liquid loading. The reservoir is currently producing above 2 MMm3/d of gas and 400 m3/d of condensate and reservoir pressure is around 230 bars. An integrated subsurface-surface study was started in 2017 with the objectives To propose an integrated plan for redeveloping the Barik Deep To identify solutions to maximize recovery of the dropped-out condensate To resolve condensate banking issues and its impact on productivity To identify new technologies allowing to increase production, to increase the field recovery (gas and condensate) and to propose a maturation plan for these technologies. In a first phase of the project, a detailed analysis of all data collected over years of field development have been used to achieve a step enhancement in the understanding and characterization of the condensation process in Barik deep. In a second phase, the study involved the construction of compositional model capturing the physics of the condensation phenomena (i.e.
Pressure-and rate-time data at wells producing the Wolfcamp shale are evaluated by a model based on a framework using subdiffusive concepts. Quantitative measures to estimate heterogeneities in the fractureand matrix-systems are provided. Multiple transfer mechanisms and complex structures govern the dynamic performance of the reservoir. Long-term depletion is governed by the matrix system; our evaluations indicate that excellent coverage is obtained in draining the lateral extents of the reservoir rock. As a physics-based model is used to evaluate responses, the suggested procedures are both extendable and scalable.
Pressure communication is commonly observed in fractured horizontal shale wells, particularly at early times when wells are placed on production. This paper will present a new technique, based on the diffusion exponent from the power-law model, to quantify connectivity in multi-stage hydraulic fractured wells with complex fracture networks. In addition to explaining the theory and analysis techniques, we will present examples utilizing measured bottom-hole pressure (BHP) from the Permian Basin Wolfcamp Shale, which illustrate the utility of this technique to better understand the relationship between completion size, well spacing, and well performance.
From PIT analyses in Permian Basin Wolfcamp Shale, we were able to establish a relationship between MPI and well spacing. The first example demonstrates analyses of PITs between wells during the production phase and also shows how connectivity between wells diminishes over time. A second example applies the same analysis techniques to quantify inter-well connectivity during the post-stimulation phase by analyzing a pressure falloff (PFO) after communication with other wells. A third example illustrates an application of desuperposition to remove the effect of a power-law pressure trend on interference tests.
Techniques to analyze PITs assuming radial or linear flow have been previously developed; however,
Crucial milestones are reached during these relatively short periods which are however characterized by high risks and high expenses. Thorough preparation and intense cooperation among various disciplines are therefore required to make them a success. This session shall focus on how to improve future operations in the East-Med by reducing risks with adequate planning, coordination, or technologies, or by increasing efficiency through synergies, simplification, and standardization. Presentations and papers should highlight such solutions, either building on specificities of the East-Med context and recent local experiences, or highlighting other experiences that might be applicable in the East-Med. A wide variety of topics can be covered, including but not limited to the optimization of data acquisition or logistics, the management of geological uncertainties (salt stability, pressure regime, etc.) while drilling, and the installation of infrastructure (pipeline, subsea equipment, etc.).
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited.
This paper presents a new workflow comprised of using hydraulic fracture modeling outputs (effective length, height, and conductivity) for the next step - a discrete fracture flow model which visualizes the drainage pattern in 3D based on history matched production data. The first part of the paper is designated to fracture forward modeling and prediction of the proppant placement geometry and conductivity of hydraulic fractures in a multistage horizontal well. The influence of wellbore deviations and other local initial conditions are all taken into account and explain localized fracture initiation, fracture asymmetry, and propagation, as well as proppant placement efficiency. The primary model focus is on the creation of fracture conductivity maps, one for each transverse fracture. The second part of this study shows the process of import and conversion of 2D fracture conductivity maps for further use in fluid flow allocation to the individual fractures.