Al-Samhan, A. M. (Kuwait Oil Company) | Gurpinar, O. M. (Schlumberger) | Ansarizadeh, M. (Schlumberger) | Wang, J. T. (Schlumberger) | Moreno, J. O. (Schlumberger) | Sinha, S. (Schlumberger) | Garmeh, G. (Schlumberger) | Giddins, M. A. (Schlumberger) | Rincon, A. (Schlumberger) | Kovyazin, D. (Schlumberger) | Samad Ali, S. (Schlumberger) | Gomez, E. (Schlumberger) | Banagale, M. R. (Kuwait Oil Company) | Burman, K. R. (Kuwait Oil Company) | Al-Houti, R. A. (Kuwait Oil Company) | Filak, J. M. (Kuwait Oil Company) | Al-Rashaid, M. (Kuwait Oil Company) | Ma, E. D. (Kuwait Oil Company) | Bond, D. J. (Kuwait Oil Company)
A major numerical modelling project was performed with the objectives of develop a more robust model for development planning studies. The second was to gain a better understanding of "reservoir dynamics", in particular aquifer influx, the lateral pressure distribution and gross fluid movement within the major reservoirs of the Wara–Burgan sequence and the flow between them.
The challenges and implemented solutions of history matching a reservoir model of a huge, complex field with multiple production zones, many wells and large volumes of production and surveillance data are described in the context of a recently completed study of Wara–Burgan reservoir in the giant Greater Burgan field. Additional challenges due to possible mechanical problems in wells and uncertainties in production and injection data, as usually experienced in mature fields, are also discussed.
The work started with reviews of basic engineering data, previous simulation studies and the regional geology. It was the first project for this field in which modern assisted history matching (AHM) techniques were applied. The main enablers for this were increased computational resources and the availability of new generation high-performance reservoir simulators. AHM techniques were used to help better define "high level" features of aquifer properties, pressure communication and gross fluid movement within and between the main reservoir units. A large emphasis was given to matching the pressure data from RFTs and cased-hole saturation estimates.
A combination of AHM and more traditional calibration methods have enabled improved models of the Wara-Burgan reservoir to be developed. These models account for the gross aspects of pressure and fluid movements in and between major reservoir units and provide a reasonable match of the performance at field, reservoir unit and gathering center (GC) levels. The use of AHM techniques and special plots to assess the quality of the pressure match have enabled better characterization on permeability levels and allowed lateral pressure gradients to be better represented. As the match was refined, issues with well histories become more apparent and the approach to dealing with these problems is discussed. Matching the apparent remaining oil distribution was facilitated by extensive tools that allowed easy comparison of simulation with both saturation estimates at wells from cased-hole logs and to interpreted saturation maps.
The available workflows, simulation tools and computing environment also allowed models with different levels of refinement (4 to 28 million cells) to be used to address concerns about numerical resolution and upscaling.
Base "Do-Nothing" prediction cases were also performed. These gave some insight into how sensitive prediction results would be to model calibration assumptions.
Development of the current representative numerical model for the main (Wara – Burgan) reservoir of the giant Greater Burgan field has allowed the major features of pressure communication, fluid movement and current pressure and fluid distributions all to be captured in a geologically plausible setting.
The approach to using very large volumes of data, including log data, in the AHM work and the novel tools used to assist visualization of match quality will be discussed.
Productions from oil and gas reservoirs can induce significant pressure and temperature changes at the wellbore. The temperature signal is sensitive to reservoir properties and production parameters which can be very useful in characterizing the reservoir. In this work, we introduce novel analytical solutions to determine the temperature signal associated with theproduction of slightly-compressible hydrocarbon from a vertical well, and apply the solutions to the production from oil and gas reservoirs. Our procedures to obtain the analytical solutions from the governing equation involve making relevant assumptions that allow rigorous solutions to be constructed using Laplace transform. We extend the analytical solutions to include the near-wellbore damage, and to characterize the damaged zone.
Our results of the analytical models are benchmarked with those from a commercial numerical simulation software. We substantiate that the Joule-Thomson effect on the temperature profile is significant in near-wellbore region, and adiabatic expansion effect extends the radius of investigation of the transient temperature signal. The damaged zoneanalytical solution shows that damaged zone radius and permeability separately affect thetemperature transient signal. This isunlike the pressure transient response for which the effect of damage zone properties is lumped into a single parameter, i.e. the skin factor. The analytically derived equations for slopes of Joule-Thomson and adiabatic expansion effects in undamaged and damaged reservoir present very close agreement with those obtained numerically. We provide semi-log temperature interpretation techniques to determine the reservoir permeability and porosity, and damaged zone radius and permeability.
Natural fractures represent planes of weakness within tight dense reservoirs in Abu Dhabi fields. It is likely that the fractures types, fracture density and orientation will influence hydraulic fractures initiation and propagation. Thus, the interaction between natural fractures and hydraulic fractures is the key objective of this paper. Limited studies have been conducted on natural fractures in Abu Dhabi, from this perspective and this represents a clear gap in our understanding. This paper addresses a workflow to predict the natural fractures that will enhance the hydrofrac initiation and propagation.
There are, however, several concerns related to the dense zones exploration and production, as they are associated with hydraulic fracturing. There is also a debate on the natural fractures impact on the hydrofrac initiation and propagation. In addition, which fracture types, if they will slip or reactivate, and bedding planes corridors. Accordingly, there is a need for understanding the behavior of natural fractures, and their critical stress state. Therefore, there is a need to assess the interactions between natural fractures from the borehole images and core, and their presence on seismic attributes.
The workflow integrates multidisciplinary data aimed to optimizing our understanding of hydraulic fractures and their relations to the natural fractures. Seismic (interpreting key seismic horizons and generating attributes), Bore Hole Images (BHI), Core, wireline logs, CT scan, and Rock Mechanics testing (RMT) were used to characterize the fracture system and build a 1D-MEM (Mechanical Earth Model). On top of that, reservoir heterogeneity and relation to tectonic deformation events were established.
Critically stressed fractures are opened when exposed to additional stress, and can act as pathways for fluid flow. The studied reservoirs showing critically stressed fractures that influence the hydraulic fracs. Most of the reservoir units are dominated by the NW, WNW, NE to E-W fracture and microfault trends, but show the dominance of the NW trend. The spatial distribution of microfaults, hybrid fractures and pure opening mode fissures with wide variations in strike appears to be related to their location with respect to the crestal axis of the main folded fields and in the faulted zones relative to the location between the strike-slip segments. Only fractures with certain dip and dip azimuth could be critically stressed. From the stereoplot, it can be observed that four groups are considered as critically stresses, these are:
Technical contributions and implications of these results include hydraulic fracturing initiation and propagation enhancement through the presence of critically stressed fractures for optimum production and correctly hydraulic fracs design.
Marhoon, Nadhal Al (Petroleum Development Oman LLC) | Masroori, Haitham AL (Petroleum Development Oman LLC) | Abdul-Majid, Imran (Petroleum Development Oman LLC) | Ajayi, Ayotunde (Petroleum Development Oman LLC) | Sandoval, Daniel (Petroleum Development Oman LLC) | Khan, Raees Ahmed (AAPG, Petroleum Development Oman LLC) | Qasmi, Liali Al (Petroleum Development Oman LLC)
The Tight Gas Reservoir (TGR) top structure is well defined in seismic data and can be interpreted across the entire area of North Oman. It is being identified as an extremely tight, disconnected, low porosity, low permeability and High Pressure – High Temperature (HPHT) reservoir, and thus presents unique challenges to harness its full production potential. Therefore, to optimise the subsurface location and ensure placing a successful well, the following approaches were implemented.
Firstly, full 3D geological model was generated to reproduce the reservoir heterogeneities and sedimentological behaviour of the TGR. Secondly, sweet spot identification techniques were used due to the heterogeneity nature of TGR properties in order to locate the optimum subsurface location. Lastly, a well completion strategy centred on hydraulically fractured cased-hole wells with immediate production to mitigate formation damage was implemented. This is achieved via abrasive jetting and thermal conductivity techniques to induce micro fractures that vastly enhanced the fracture efficiency, with velocity strings combined with depletion compression.
Furthermore, the characterization and simulation efforts are aimed to test the longevity of the wells in an Early Production System (EPS) to evaluate the optimal well count and spacing for the full Final Development Plan (FDP). Also, the interference between the wells in this tight formation has been studied. Data gathering activities encompasses formation evaluation logs, core analysis data and well test data.
The surface development concept is based on staged field development, with long term testing as the first milestone. EPS have been selected to provide long term production data gathering opportunity for assessing the reservoir and well performance behaviour in order to aid in defining the FDP.
This paper will highlight the success of unlocking tight, unconnected gas and describe methodologies applied to aid fully integrated subsurface loop development. Reservoir characterization, model creation and simulation challenges linked with the appraisal results will also be discussed.
Streamlines provide detailed information about dynamic fluid paths and connectivity between injectors and producers. Fuzzy logic, on the other hand, can simulate human thinking and handle different categories of information including linguistic, imprecise, approximate, and overlapping to name a few. This paper presents a genuine approach for field injection optimization using a streamline-based fuzzy logic system.
In a previous paper, we presented an adaptive streamline based fuzzy logic system that uses three input parameters namely injection efficiency (IE), water cut (WC), and injection loss to aquifer to assign an injector ranking index (IRI) according to injectors' performance. In this paper, we enhanced the streamline based fuzzy logic workflow to smartly re-distribute water injection by accounting for operational constraints and number of supported producers in a pattern in addition to the IRI. The new workflow examines the low performers (i.e., low and medium IRI categories) and assigns different injection reduction factors for each injector in these categories. Then, the total amount of reduced injection is assigned to high performers (i.e., high IRI) while ensuring no operational constraints is violated such as BHP and capacity of pumps.
This approach has been tested on a large-scale DPDP simulation model. The area of interest in this field has two rows of injectors: downdip and updip. The updip injectors are the focus of the study. The results of this case study show noticeable improvements in injection efficiency for most wells in the area of interest ensuring better sweep, good pressure support and improving cumulative oil production.
We believe combining both technologies namely streamlines and fuzzy logic can provid reservoir engineers with a robust decision-making tool to attain a more successful field-wide water injection strategy.
Candela, T. (TNO Applied Geosciences) | Osinga, S. (TNO Applied Geosciences) | Veer, E. F. van der (TNO Applied Geosciences) | Heege, J. H. ter (TNO Applied Geosciences) | Fokker, P. A. (TNO Applied Geosciences)
One way to improve our understanding of the reservoir behavior at depth is to analyze the ground surface response during reservoir exploitation. During reservoir exploitation, pressure changes can lead to compaction/dilation at depth resulting in ground surface displacements. Disentangling the information encrypted in the surface displacement data should therefore provide information about the reservoir behavior at depth. In the last decade we developed a workflow imbricating fast geomechanical forward models and a surface displacement data assimilation scheme to improve our (i) understanding of the subsurface processes and (ii) improve predictions of reservoir behavior in terms of reservoir management. Here we present two case studies to illustrate the versatility and robustness of the workflow. The first case study identified undepleted gas compartments in a strongly faulted and compartmentalized reservoir in a Dutch gas field through inversion of combined surface levelling and InSAR data. The second case study constrained spatial variation in aquifer activity around another Dutch gas field by directly employing ascending and descending PS-InSAR line-of-sight data. We also show the benefit of using multiple data assimilation for constraining parameters in forward models that contain non-linearity. Additionally, we present a novel approach for an inversion workflow that includes uncertainties in every step of the inversion process in a single integrated inversion procedure.
Guo, Hu (China University of Petroleum) | Li, Yiqiang (China University of Petroleum) | Li, Yanyue (CNOOC) | Kong, Debin (China University of Petroleum) | Li, Binhui (China University of Petroleum) | Wang, Fuyong (China University of Petroleum)
Although Alkali-Surfactant-Polymer (ASP) flooding enhance oil recovery (EOR) technique has been put forward many years ago, it was not until 2014 that it is first put into industrial application in Daqing Oilfield in China. Under such low oil price, ASP flooding advance in China provides confidence for ASP flooding as a chemical EOR technology. In 2014, ASP flooding entered into industrial application stage first time in history. Crude oil production from ASP flooding in 2015 and 2016 in Daqing Oilfield was 3.5million and 4 million ton, which accounts for the 9% and 11% total oil production respectively. In 2016, another large scale ASP flooding field test in high temperature (81 °C) reservoir in central was seen staged incremental oil recovery 7.7% in central well zone. 30 ASP flooding field tests in China were reviewed to help promote wiser use of this promising technology. ASP flooding in Daqing Oilfield deserves most attention. Strong alkali (NaOH) ASP flooding (SASP) was given more emphasis than weak alkali alkali (Na2CO3) ASP flooding (WASP) in a long time in Daqing, lower interfacial tension(IFT) of surfactant and higher recovery in presence of NaOH than Na2CO3 the most important reason. Other ASP flooding field tests finished in China are all Na2CO3 based, including one using mixture of NaOH and Na2CO3. With progress in surfactant production, a recent large scale WASP field tests in Daqing was seen incremental oil recovery of near 30%, higher than most previous SASP ones, and near to the most successful SASP one. However, this most successful SASP was partly attributed to the weak alkali factor. Recent studies shows that WASP incremental oil recovery factor could be as good as SASP but with much better economic benefits. According to Daqing Oilfield review, the equipment IFT is more determinant than dynamic IFT in contribution to displacement efficiency, thus it is better to choose lower dynamic IFT when equilibrium IFT met the 10-3 orders of magnitude requirement. However, it is impossible for many surfactants to form equilibrium IFT, thus dynamic minimum IFT was chosen as criteria. For low acid value Daqing crude oil, asphaltene and resin component plays a very important role in reducing oil/water IFT, and asphaltene is believed more influential, though more work are required to answer this controversial issue. Progress in surfactant production, overcoming of scaling and produced fluid handling challenger is the foundation of ASP industrial application. Dynamic adjustment in ASP flooding is common practice in Daqing. For the compatibility between ASP and formation pore structure, especially considering emulsion and formation damage, no satisfactory standards are found yet. Further work should be on emulsification effect in ASP flooding. Mixture of cation and anion surfactants used in Henan Oilfield may be a good choice to face the high temperature challenge. Ultra-high temperature reservoir ASP flooding with organic alkali is under investigation and a field test is in schedule. It is very difficult to carry out ASP flooding in high temperature and high divalent cation reservoir and no success was seen in such kind of reservoirs in China. According to one field test, EOR routine should be selected with consideration of residual oil type to decide whether to enlarge sweep volume or/and displacement efficiency. Micellar flooding failure in Yumen Laojunmiao (YM-LJM) reservoir makes subsequent field tests choose the "small concentration large slug" technical route instead of "high concentration small slug" one like YM-LJM. ASP flooding can increase oil recovery by 30% and control the cost below 30 US dollar/bbl, thus it can be used to face low oil price challenge.
Dernaika, Moustafa R. (Ingrain Inc) | Mansour, Bashar (Ingrain Inc) | Gonzalez, David (Ingrain Inc) | Koronfol, Safouh (Ingrain Inc) | Mahgoub, Faris (Ingrain Inc) | Al Jallad, Osama (Ingrain Inc) | Contreras, Mauricio (Ingrain Inc)
Determination of Reservoir Rock Types (RRT) is one of the main parameters in the process of reservoir modelling and simulation. In carbonate reservoirs, the rock typing process is challenging due to multiscale heterogeneity with varying pore types and complex microstructures. The objective in this paper is to select representative samples from a heterogeneous core (350 feet) and establish unique reservoir rock types as well as model permeability along the entire core length based on textural analysis, geological interpretations and petrophysical measurements.
Representative core plugs were selected in a full-diameter heterogeneous core from a carbonate reservoir in the Middle East. The sample selection was based on statistical distribution of porosity and CT-textures in the core. The porosity and textural variations were determined along the core length at 0.5 mm resolution using advanced dual energy X-ray CT imaging. Plug-scale rock types were established based on micro-textures and pore types using thin-section photomicrographs, mercury injection analysis and poroperm measurements. The micro-texture analysis (grainy, muddy, mixed) and pore types were linked to the poroperm data. The micro-texture information was then upscaled to the entire core length using CT-textural analysis.
The porosity and permeability data were fitted into unique trends that were derived from the detailed textural analysis. This process provided the link between the poroperm trends and the different textures in the core enabling permeability and rock types to be upscaled to the entire whole core intervals. Variation of reservoir rock types was studied for each poro-perm trend. The different trends were mainly controlled by the different rock micro-textures whereas the extent of the trend was due to different diagenesis processes (i.e. dissolution, cementation & compaction).
This paper describes a novel approach of combining textures with porosity to model permeability and rock types at the plug scale and core level. A unique dual energy CT technique was used to ensure that all the core property variations were well represented in the plug-scale core analysis measurements.
In 2003, an aggressive drilling program started in Mansoura area in the onshore Nile Delta, with high success ratio. The program benefited from the direct hydrocarbon indicators provided bythe post stack seismic data. After proving hydrocarbon presence in the field many reservoirs explored, however some challenges appeared lately. The most important challenges are the lithology and fluid discrimination due to the shale behavior, furthermore, the delineation of different reservoir properties like clay content, water saturation, and porosity proved to be challenging.
Analysis of pre-stack seismic data for different reservoir properties prediction is commonly used for reservoir characterization. To enhance pre-stack seismic data quality some seismic gathers preconditioning flowcharts have been applied on the pre-stack data. The wavelet spectral analysis has been performed after conditioning the data then different techniques like the AVO simultaneous inversion, AVO analysis and density inversion have been applied on both west Dikirnis and west Khilala fields.
Rock physics model building was carried out in the onshore Nile Delta to link the elastic properties and the reservoir properties. The model implemented in the unexplored areas within the concession to minimize the drilling risk of the delineated prospects. The rock physics model built in the area of study helped significantly to discriminate between wet sand, shale and gas sands. The middle and late Messinian are typically sand rich sections with excellent reservoir quality encountered in the drilled wells within both fields. Different reservoir properties predicted using the advanced inversion techniques in addition to the well data showing strong correlation at the well locations.
The reliability of the far and ultra-far seismic data was encourenging. The cross-plot of the acoustic impedance versus shear impedance represents a useful technique in the onshore Nile Delta for sand and shale discrimination. Using Elastic impedance logs we can discriminate the water bearing sand, hydrocarbon sand and shale especially at the ultra-far angle.
Yongbin, Wu (RIPED of CNPC) | Xingmin, Li (RIPED of CNPC) | Wanjun, He (Xinjiang Oilfield of CNPC) | Fang, Zhao (RIPED of CNPC) | Yueyue, Fang (China University of Petroleum) | Weinan, Ai (China University of Petroleum) | Youwei, Jiang (RIPED of CNPC) | Xiaoxiong, Liu (RIPED of CNPC)
In order to massively enhance the performance of heterogeneous SAGD projects, the targeted Electrical-Heating in poor steam chamber segment assisted SAGD (EH-SAGD) was proposed, the simulation method was established coupling geo-mechanics of both payzone and interbeds, and delivery of energy by electrical heating into the subsurface. The screening criteria of EH-SAGD was formed and the typical SAGD wellpair performance was predicted and compared.
As the EH-SAGD is quite complex in its mechanisms, the precise simulation must reflect the impact of these mechanisms. Therefore, systematic experiments were carried out firstly to provide the key parameters of the rock and fluid to the simulation model. The geo-mechanic characteristics of barriers with different rock types was obtained by tri-axial compression tests, and the mineral composition change and reaction at elevated temperatures were obtained by means of X ray diffraction and interpretation.
The numerical simulation model of EH-SAGD was established based on the experimental results. The geo-mechanic model were added into the simulation based on the experimental results illustrating the Young's modulus, Poisson's ratio, compression strength, yield stress and the corresponding changes of the porosity and permeability.
From numerical simulation, the screening criteria for reservoirs that feasible for EH-SAGD was optimized by multi-parameters. The SAGD wellpairs with barriers in between the horizontal segments were the applicable targets for electrical heating. The combination heating of downhole heaters in both injector and producer was recommended for rapid breakthrough of the barriers. The heat power of the heaters with time was also optimized which required the highest power of 2500W/m for each heater. Following which a typical SAGD wellpair was selected to make the comparison. It is simulated that by targeted electrical heating, the oil drainage route can be established, the steam chamber along the whole horizontal segment can be developed, and the oil rate can be enhanced by 45% from conventional SAGD. It is forecasted that the oil recovery factor of EH-SAGD is 12.1% higher than SAGD.
The results indicate that the EH-SAGD has encouraging effect to enhance the oil rate, steam chamber uniformity, and the final oil recovery factor, which is a practical and novel EOR approach for heterogeneous SAGD reservoirs.