Understanding the changes in the saturation within a reservoir undergoing enhanced oil recovery (EOR) is crucial to optimizing production. We debut a novel, multiphase fluid flow modelling code, TOGA, to assist in modeling gas, oil, and water phases within the reservoir, and combine its output with time-lapse Depth to Surface Resistivity data in a case study involving an EOR reservoir. The results show the potential for combining the two methods to improve our understanding of reservoir saturation over an extended period of time.
Presentation Date: Tuesday, October 16, 2018
Start Time: 9:20:00 AM
Location: Poster Station 15
Presentation Type: Poster
The M prospect is located in the B block flanking the northern boundary of the Doba basin in Chad, Africa. D-1, M-1 and M-2 wells were drilled by OPIC Africa Corporation in 2015 and 2016 respectively. After DST testing, M-1 and M-2 wells successfully discovered oil with good production rate. To further understand the spatial thickness distribution of the tested reservoir sand in order to estimate the in place oil reserve associated with the discovery wells, interbedded thin sand interpretation technique was built through spectrum decomposition modeling and analysis. Four stratigraphic 2D channel filled sand models were built by integrating the P-velocity and the density logs of two discovery wells. Sand thickness interpretation pitfall associated with wedge model was recognized based on the study result. Based on the modeling results, we concluded that dim amplitude response may also be interpreted as interbedded thin sands rather than zero thickness sand. This new sand thickness interpretation technique was applied to the sand thickness interpretation of spectrum decomposed 3D seismic amplitude volumes. The sand interpretation results based on spectrum decomposition modeling is consistent with the drilling results.
Presentation Date: Monday, September 25, 2017
Start Time: 2:15 PM
Location: Exhibit Hall C/D
Presentation Type: POSTER
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
Wang, Jing (China University of Petroleum) | Liu, Huiqing (China University of Petroleum) | Zhang, Hongling (China University of Petroleum) | Luo, Haishan (The University of Texas at Austin) | Cao, Fei (The University of Texas at Austin) | Jiao, Yuwei (CNPC RIPED) | Sepehrnoori, Kamy (The University of Texas at Austin)
Numerical simulation is important to understand and predict the development of oil and gas reservoirs. Existing commercial simulators, such as CMG, ECLIPSE and VIP, have been widely used in the past several decades for their robust performance in computing and scaling. In these reservoir simulators, the fluid flow models are based on Darcy's law or its extended form; the volume of the adsorbed phase or component is overlooked as well. While this is acceptable for conventional oil/gas reservoirs or chemical flooding reservoirs, the gas flow regimes such as slippage flow, transition flow, and molecular-free flow significantly is deviated from Darcy flow for shale gas reservoirs. Besides, a large portion of the gas is stored in the pore in the form of adsorbed gas. If the volume of the adsorbed gas is still overlooked, the volume of free gas and original gas in place (OGIP) will be seriously overestimated. For the above reasons, it is commonly thought that existing commercial simulators could not be ideally used to simulate the development of shale gas reservoirs. Hence, it is desirable to attain a feasible approach to correct the petro-physical properties of shale gas effectively within the commercial simulators, in order that one can use them to accurately simulate the development of shale gas reservoirs. In this paper, we first derived the correction formulas for the bulk porosity, free gas saturation, and connate water saturation used for correcting the disregarded volume of adsorbed gas in commercial simulators. Then, we derived the models of permeability and porosity multipliers in matrix considering gas adsorption/desorption, geomechanics, non-Darcy flow regimes, and diffusion of adsorbed layer. Finally, the above models were used to attain the corrected petro-physical properties for simulating gas production based on the practical properties of shale gas reservoirs using commercial simulators. The validation was performed by comparing the simulation results of commercial simulator with the published mechanism simulator using gas field data. The results show that the simulation results using commercial simulator achieve good agreement with the published mechanism simulator with the corrected petro-physical properties. The corrections of bulk porosity, connate water saturation, and free gas saturation are very essential. The correction formulas for these properties can largely decreases the error of OGIP and the calculated gas production. Both permeability and porosity multipliers are the functions of gas pressure, but they are not a monotone decreasing/increasing function. The gas production may be significantly overestimated or underestimated without consideration of these characteristics of shale gas in different fields. The contributions of different mechanisms are also demonstrated using the commercial simulator. This work can evently solve the issue that existing commercial simulators cannot accurately simulate shale gas production. The researchers can easily use these commercial simulators with these corrected formulas, which is a great progress for modeling the development of shale gas reservoir.
Fan, Honghai (China U. of Petroleum (Beijing)) | Zhou, Haobo (SINOPEC Research Inst. of Petroleum Engineering and China U. of Petroleum (Beijing)) | Wang, Guo (SINOPEC Research Inst. of Petroleum Engineering) | Peng, Qi (China U. of Petroleum (Beijing)) | Wang, Yiqing (China U. of Petroleum (Beijing))
Hydraulics play an important function in many oil field operations, in the case of drilling, with the implementation and promotion of management pressure drilling technology, the role of accurate hydraulic parameter predictions becomes vital for drilling. This paper describes a utility hydraulic calculation model for Herschel-Bulkley (H-B) rheological model.
Firstly, the explicit equation between the wall shear stress and volumetric flow rate of H-B fluid flow in pipe and annuli were obtained. Then, the accurate numerical solutions of wall shear rate and shear stress both in pipe and annuli were obtained. Secondly, we defined a new generalized flow behavior index and effective diameter for H-B fluid annular flow. The generalized effective diameter accounts for the effects both of annuli geometry and fluid rheology but which is different from that was proposed by Reed & Pilehvari. Moreover, through the effective diameter we link the H-B fluid flow both in pipe and annuli to Newtonian pipe flow. At last, a general expression of generalized Reynolds number was derived from this model in view of generalized flow index is non-constant. Then, a theoretical calculation method was proposed for the generalized flow index of both pipe and annular flow and a uniform pressure drop calculation model was obtained. The predictions of the improved hydraulic model have been compared with an extensive set of experimental data. The comparison of different fluids both in pipe and annulus show very good agreement over the entire range of flow types.
Finally, the utility model has been applied in several wells in Sichuan basin and Tarim basin for monitoring real-time hydraulics while MPD, and there is an excellent match between the model and measured data. Therefore, it can be seen that this utility method can be applied to provide more accurate estimations of hydraulic parameters in drilling engineering.
The determination of hydraulic parameters in circulating system has been an objective of technology for almost as many years as rotary drilling has been in existence. As deeper well are being drilled in searching for new crude oil and natural gas reservoir, the prediction and control hydraulics of drilling becom increasingly improment. Especially, with the implementation and promotion of the management pressure drilling (MPD) technology, the role of accurately predicted hydraulic parameters becomes vital portion of drilling operation, which provided technical support for engineering decisions to ensure high-quality fast drilling (Li et al. 2011; Yu et al. 2011).
Nayagawa, Asmau (Shell Petroleum Development Company of Nigeria Ltd.) | Amrasa, Kefe (Shell Petroleum Development Company of Nigeria Ltd.) | Ayeni, Olukayode (Shell Petroleum Development Company of Nigeria Ltd.) | Sa'ad, Abdul-Wahab (Shell Petroleum Development Company of Nigeria Ltd.) | Osho, Olaseni (Shell Petroleum Development Company of Nigeria Ltd.)
Reservoir quality in terms of Net-to-Gross (NTG) remains one of the critical components in determining the Hydrocarbon-initially-In-Place (HCIIP), recoverable reserves and production rates of any producing field. Often times, fluvial channel and shoreface deposits are credited to have very good reservoir qualities, hence are choice candidates for completions post-drill of the well. In addition, examples exist of heterolithic sands from which considerable reserves have been recovered during the life-cycle production of the Cream Field in the Niger Delta basin, Nigeria. Improved production from these reservoirs is associated with optimization of well designs. Heterolithic deposits are made up of inter-bedded sand and mud/shale. These deposits are typically laid down in environments like the tide dominated deltaic and estuarine environments as found in the Niger Delta of Nigeria.
The Heterolithic sands found in the field to be discussed are mainly lower shoreface sands with lesser transgressive sand units; lower energy, variably sorted sandstones which are typically finely laminated and commonly intensely bioturbated. There is a continuous transition between heterolithic and shoreface sands. Reservoir quality tends to increase upwards as the heterolithic sands grade into shoreface sands.
The sands have poor Kv/Kh values due to presence of shale laminates within the sand deposits. This exacerbates the poor sweep efficiency of the oil with high possibility of by-passed oil. The overall impact of these challenges is low recovery factors assigned to the sands.
Due to the properties and nature of the heterolithic sands mentioned above, there is usually low pressure support due to poor aquifer connectivity as a result of the depositional environment, thus triggering a depletion drive mechanism.
Interestingly, some of these heterolithics hold considerable recoverable volume that makes the exploitation of such reserves important. Such is the case offshore Norway, Alaska, Canada, Venezuela, Russia, Nigeria and indeed world-wide. As a result, production optimization therefore becomes critical to maximize recovery from wells completed on this facie type.
The paper reviews the occurrence of this heterolithics in a field in the Niger Delta, the challenges faced with the current completion strategy and the reservoir management practices. A major challenge as observed in conventional crestal completion on the structure is early gas breakthrough from secondary gas cap formation. Methods of enhancing recovery from heterolithics using improved completion strategy and the requisite reservoir management practices are set forth in the body of the paper.
Completion strategies like horizontal wells targeted at the good quality sands has shown an additional potential 1300bopd (seen in the performance of the only horizontal well in the field) as compared to performance of conventional wells, simulation study of water injection and gaslift has also indicated an increase in reserves by 10MMstb.
Block size estimation is required to optimize support design, to estimate volumes for rockfall catchment systems, and is an integral part of many rockmass classification systems. The most common problem with existing methods used to determine block size is that a single, representative “average” block is calculated. By using the average intensity and average fracture size in analyses, the possibility for large blocks to form is disregarded. Equally important may be the presence of zones comprised of very small blocks that cannot be supported in the same way that the average sized block would be. To attempt to incorporate the distributions of fracture sizes and intensities encountered in a rockmass, DFNs have been used to create block size distributions for a given set of parameters. This work compares existing estimators of block size to outputs from DFN modeling. A set of descriptive parameters are presented for block size distribution curves. Charts to estimate block size distributions for different geometries are presented.
This paper presents a case history of defining the field development plan for a complex; heavily faulted layered; undersaturated oil reservoir, with significant degrees of structural and production uncertainties. In such case, good reservoir management practices and reservoir monitoring are the main keys to understanding the reservoir behavior.
The reservoir has numerous challenges, which complicate reservoir management; like complex geology, pressure support for different layers, water injection optimization, scale depositions, and commingled production which introduces uncertainties regarding the production and injection contribution. This leads to difficulties to identify bypassed oil in the reservoir. Therefore frequent production logging, monitoring the producing water salinity, and key data from wells and RFT/MDT of the new infill wells were used for managing such uncertainties'. This served as primary keys to identify different vertical and lateral flow barriers, and was used as a basis for water injection optimization in such challenging conditions.
The reservoirs were studied by means of analytical methods and integration approach of wells' and reservoir surveillance data for understanding the structural configuration, investigate various production problems, optimize water injection strategy, and identify bypassed oil and poorly swept areas. The methods defined an extensive portfolio of infill drilling and other cost saving rigless activities to restore production potential of the field. This approach added about 22 MMSTB of oil reserves which represent 8 % increase in the ultimate oil recovery, and flattened the oil production for more than 5 years.
New infill wells were confidently identified to achieve all of the following objectives a) access bypassed reserves b) access attic oil reserves c) adding another drainage point to the existing producers. The presented reservoir management practices has proven its ability to timely support the operational decisions, pinpoint infill wells, and prolong the life of a mature asset. It is not moving away from detailed dynamic model, but these practices are required in similar uncertainties conditions to develop right sense of understanding of reservoir behavior, and provide invaluable input data which adds credibility to the dynamic model.
Ras Budran oil field, located in the northern Belayim offshore area; about 4 km west to Sinai Gulf of Suez coast (Fig. 1), is operated by the Suez Oil Company (SUCO). The field was discovered in 1978 by drilling the discovery well EE85-1 which penetrates several sand stone reservoir units extending over about 1800 FT to an original oil water contact at 12350 Ft. After discovery three appraisal wells were drilled with the objective of defining the field boundary and determine the total oil in place, and hence decide the commercial viability of the project. Subsequently the field has been developed from three small offshore platforms have a total of 29 slots.
The structural configuration of the Ras Budran field is a structurally complex pre-Miocene reservoir, severely strained by faults of different throws and aligned in various directions. The faults divide the reservoir to three main fault blocks, A-, B-, and C-Block (Fig. 2). The sedimentary sequence ranges from Paleozoic to recent. The main reservoirs involve Nubian C & D (Carboniferous and older), Nubian A (Carboniferous - Early Cretaceous), and Raha Sands (Cenomanian) (Fig. 3).
Abstract: We present a 3D-DDA formulation that uses an explicit time integration procedure and an efficient contact detection algorithm optimized to minimize the computational effort. The advantages of the explicit formulation are that the global stiffness matrix does not need to be assembled and the linear equations do not need to be solved by matrix inversion. Consequently, the computational effort and memory requirement can be reduced considerably, which is important for efficient solution of large 3D problems. In addition, the computational efficiency is increased by eliminating unnecessary contact computations using a grid based nearest neighbor search. The grid divides space into a number of cells of equal size and each object is then associated with the cells it overlaps. As only objects overlapping a common cell can possibly be in contact, in-depth tests are only performed on objects found sharing cells with the block tested for collision. The contacts between the blocks are detected by using Fast Common- Plane (FCP) approach. The halfedge (HE) data structure approach is used to handle the navigation into the topological information associated with polyherdral objects (vertices, edges, faces). The halfedge data structure allows for quick traversal between faces, edges, and vertices due to the explicitly linked structure of the network. Examples are provided which demonstrate the capabilities of new algorithm and the size of problem that can be analyzed.
Fourie, Bernard (Brunei Shell Petroleum Co. Sdn. Bhd.) | Marpaung, Billman (Brunei Shell Petroleum Co. Sdn. Bhd.) | Jansen, Rene (Brunei Shell Petroleum Co. Sdn. Bhd.) | Wong, Andrew (Halliburton) | Mok, David (Halliburton Energy Services Sdn. Bhd.)
Copyright 2013, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26-28 March 2013. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract Brunei Shell Petroleum (BSP) operates the mature South West Ampa (SWA) and Bugan Fields in Brunei Darussalam. The fields, located 10 to 21 kilometers offshore Brunei in water depths ranging from 10 to 40m, are major sources of oil and gas production. Controlling sand production is a key completion challenge as the reservoirs are composed of multilayer unconsolidated sands, requiring sand control for safe production. Cased-hole, stack-pack systems were considered as the default solution for shallow reservoir zones and wells.