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.
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.
Rock strength is an important property to measure for determining its effect on drilling, wellbore stability, and potential well completions associated with hydraulic fracturing of unconventional reservoirs. The industry traditionally relies on elastic moduli measured from core plugs to determine the stress anisotropy to predict the extent of hydraulic fractures. This provides some estimate of the expected stimulated rock volume in unconventional reservoirs. Rock strength however based on the finding of this study could also be a factor that needs to be considered for designing hydraulic fracturing plans to stimulate production from the rock volume. However, rock strength is difficult to measure in highly laminated source rocks comprising unconventional reservoirs. The existence of weak, horizontal bedding planes within the laminated rock fabric creates anisotropy that influences the rock strength values obtained. Moreover, drilling and extracting intact horizontal, vertical, and diagonal core plugs to test the effects of anisotropy on the rock strength is difficult to achieve. Often, the plugs fracture during extraction due to the laminated fabric. To compensate for the challenge of extracting intact core plugs from these lithofacies, this study proposes that rock strength can be estimated without the need of extracting core plugs. Instead, a new method is demonstrated where non-destructive rebound hardness measurements are collected across a specifically gridded, slabbed rock surface to provide an estimate of the rock strength. The collected rebound hardness values are converted into unconfined compressive strength values using an empirical algorithm. The empirical algorithm was developed using unconfined compressive strength values measured from core plugs correlated to rebound hardness numbers measured from the face of those same core plugs. The derived unconfined compressive strength values are then used to represent the source rock's mechanical characteristics which can be presented as a contour map across the surface. These results have been correlated to the mineralogy of the rock surface, quantified and mapped using micro-X-ray Fluorescence elemental maps. Differences in unconfined compressive rock strength can then be correlated to the changing mineral content of the rock surface. This non-destructive estimation of rock strength was conducted to address the challenge of relating core scale measurments to reservoir scaled analysis to improve hydraulic fracturing designs in unconventional source rocks.
It goes on to detail the mechanisms, applications, and challenges of the various sand control options in both vertical and horizontal applications. It mainly focuses on a practical project requiring the participants to apply what they have learned by selecting, designing and presenting the most appropriate sand control completion for several case study wells for both cold primary and thermal application.
Kholy, Sherif M. (Advantek Waste Management Services) | Mohamed, Ibrahim M. (Advantek Waste Management Services) | Loloi, Mehdi (Advantek Waste Management Services) | Abou-Sayed, Omar (Advantek Waste Management Services) | Abou-Sayed, Ahmed (Advantek Waste Management Services)
During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating fracture-closure pressure. However, there are situations when it is not practical to determine the fracture-closure pressure using these analyses. These conditions occur when closure time is long, such as in mini-fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the fracture faces that delays fracture closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the fracture closure can be detected. The objective of the present study is to attempt to correlate the fracture-closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation.
A study of the injection-pressure history of many injection wells with multiple hydraulic fractures in a variety of rock lithologies shows a relationship between the fracture-closure pressure and the ISIP. An empirical equation is proposed in this study to calculate the fracture-closure pressure as a function of the ISIP and the injection-formation rock properties. Such rock properties include formation permeability, formation porosity, initial pore pressure, overburden stress, formation Poisson’s ratio, and Young’s modulus. The empirical equation was developed using data obtained from geomechanical models and the core analysis of a wide range of injection horizons with different lithology types of sandstone, carbonate, and tight sandstone.
The empirical equation was validated using different case studies by comparing the measured fracture-closure-pressure values with those predicted by using the developed empirical equation. In all cases, the new method predicted the fracture-closure pressure with a relative error of less than 6%.
The new empirical equation predicts the fracture-closure pressure using a single point of falloff-pressure data, the ISIP, without the need to conduct a conventional fracture-closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and the time when the actual fracture closure occurs, which can take several days in highly damaged and/or very tight formations. Moreover, in operations with multiple-batch injection events into the same interval/perforations, as is often the case in cuttings/slurry-injection operations, the trends in closure-pressure evolution can be tracked even if the fracture is never allowed to close.
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.