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Results
Abstract Hydrocarbon reservoir performance forecasting is an integral component of the resource development chain and is typically accomplished via reservoir modeling using either numerical or analytical methods. Although complex numerical models provide rigorous means of capturing and predicting reservoir behavior, reservoir engineers also rely on simpler analytical models to analyze well performance and estimate reserves when uncertainties exist. Arps, for example, empirically demonstrated that certain reservoirs may decline according to simple, exponential, hyperbolic, or harmonic relationships; such behavior, however, does not extend to more complex scenarios, such as multi-phase reservoir depletion. Due to this limitation, an important research area for many years has been to transform the equations governing flow through porous media in such a way as to express complex reservoir performance in terms of closed analytical forms. In this work, it is demonstrated that rigorous compositional analysis may be coupled with analytical well performance estimations for reservoirs with complex fluid systems, and that the molar decline of individual hydrocarbon fluid fractions can be expressed in terms of rescaled-exponential equations for well performance analysis. This work demonstrates that, by the introduction of a new partial pseudo-pressure variables, it is possible to predict the decline behavior of individual fluid constituents of a variety of gas condensate reservoir systems characterized by widely varying richness and complex multi-phase flow scenarios. A new four-region flow model is proposed and validated to implement gas-condensate deliverability calculations at late times during variable bottomhole pressure production. Five case studies are presented to support each of the model capabilities stated above and validate the use of liquid-analog rescaled-exponentials for the prediction of production decline behavior for each of the hydrocarbon species.
- Asia > Middle East (0.93)
- North America > United States > Texas (0.46)
Abstract Individual contribution from each zone is of vital importance in wells producing from different zones from a single tubing string. Zonal production volumes are important for reserves evaluation as well as future projection with respect to processing facility. Gas analysis obtained during production phase when compared to those obtained during Drill Stem Tests can give valuable information regarding zonal contribution. Monitoring of production parameters can allow to develop a method based on thorough analysis of DST results to predict specific contribution from each zone. Bifurcation of commingled flow was based on the gradual change in key gas composition parameters. Both zones were initially tested separately and gas samples were collected and analyzed at surface. During testing, CO2 mole percentages from Reservoir 3 and Reservoir 2 were measured as 8 mol% and 5 mol% respectively. When well started commingled commercial production, initial CO2 concentration was recorded as 7.67 mol%. Factors were selected which when multiplied with initial CO2 concentrations gives the recorded CO2 concentration. The factors are the fractional gas contribution from each zone. Gradual decline in CO2 concentration suggested that the contribution from Reservoir 2 has increased over time. Results obtained by distributing the compositions received from production data according to the results obtained during well test analysis were matched by using iterative methods. Based on individual compositional contribution, volumetric contributions were attributed to each zone. Results predicted from this method were in close agreement with the results obtained from down hole logging survey performed later. Method used is general and can be applied to any well with similar characteristics. It can also be extended for three zones producing from same tubing string and reliable data from well testing is available. This can eliminate the costly requirement of down hole logging survey, production loss and risks related to well interventions. A simple yet holistic method was developed for estimating zonal contribution if reliable well test gas composition data is available. The data was compared with production data and based on the gas composition mix, zonal contribution was attributed which was also verified by down hole logging survey.
- Asia (0.69)
- North America > United States (0.47)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
A Theoretical and Practical Comparison of Capacitance-Resistance Modeling With Application to Mature Fields
Temizel, Cenk (Aera Energy) | Salehian, Mohammad (Istanbul Technical University) | Cinar, Murat (Istanbul Technical University) | Gok, Ihsan Murat (Istanbul Technical University) | Alklih, Mohamad Y. (Aera Energy)
Abstract With the advances in data-driven methods, they have become more widely-used in analysis, predictive modeling, control and optimization of several processes. Yet, as it is a relatively new area in petroleum industry with promising features, the industry overall is still skeptical on use of data-driven methods as it is a data-based solution rather than traditional physics-based solutions. In this sense, in order to shed light on the background and applications in this area, this study comparatively evaluates one of the methods used in waterflood surveillance and optimization called capacitance-resistance model illustrated on two types of mature fields with high and low-perm characteristics. Data-driven methods serve as a robust tool to turn data into knowledge. Historical data generally has not been used in an effective way in analyzing processes due to lack of a well-organized data where there is a huge potential of turning terrabytes of data into knowledge. A capacitance-resistance model is built to identify the well connectivities between the wells and then carry that knowledge to better reservoir management through optimization of injection and production in two different sets of data. In CRM modeling, analysis of injection/production data at associated injectors and producers reveals the connectivities and further optimization leads to optimum injection values. Steps and the methodology of building a CRM model using real data is illustrated to exemplify the whole process in a comparative way between two mature reservoirs. We introduce the concept of application of spatial constraints in terms of injection-producer maximum influence radius to accelerate and improve the solution where knowledge of radius of influence for an injector is known by historical data and experience. The theoretical and practical information is supported with mature field examples to investigate the factors affecting the performance of vertical wells in tight and intermediate-permeability reservoirs along with the outline of the major challenges and how to solve them. This study also illustrates the challenges of application of CRM on a tight reservoir in the order of 0.1md and comparison of the application of the method on a more intermediate-perm reservoir. Field data used in this study is from publicly available, open access source, Division of Oil, Gas & Geothermal Resources (DOGGR) website -
- North America > United States > California > Kern County (0.47)
- North America > United States > California > Ventura County (0.30)
- North America > United States > Texas > Travis County > Austin (0.28)
- North America > United States > California > Ventura Basin > Ventura Field > Santa Margarita Formation (0.99)
- North America > United States > California > Ventura Basin > Ventura Field > Pico Formation (0.99)
- North America > United States > California > Ventura Basin > San Miguelito Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- (2 more...)
Abstract Sulfur deposition has been one of the major concerns in the sour-gas industry. This is due to the significant reduction in the deliverability of a gas well. To illustrate, in deep sour gas reservoirs, elemental sulfur often exists as a trace element in vapor at reservoir pressure and temperature. Reduction in reservoir pressure and temperature due to production of gas to the surface reduces sulfur solubility in the gas phase so that the dissolved elemental sulfur precipitates in the wellbore region of the sour gas well, thus building up sulfur scale over a period. The compositional simulation model was GEM from CMG and we used WinProp for phase behavior of a generalized deep sour gas well in the Middle East. We observed that the deposition of sulfur is in the tubing and not like salt/scale deposition in the casing which is due to evaporation and super saturation in the brine phase as it produced through the perforations.
- Asia > Middle East (0.49)
- Europe (0.34)
Abstract Previous approaches to downhole flow allocation have used traditional nodal analysis software. This paper provides practical experience developing a solution for zonal flow allocation using an advanced completion and near-wellbore (NWB) hydraulics simulator. This solution was implemented in a green field development in the Middle East where three oil-producing wells completed with an intelligent well completion (IWC) system commingle production from multiple reservoirs. These smart wells were installed with interval control valves (ICVs) to control the commingled flow and permanent downhole gauges (PDHGs) to provide real-time pressure and temperature (P/T) data that were used in flow allocation.
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- (2 more...)
Abstract Sometimes electrical submersible pumps (ESPs) are deployed in oil wells to compensate for low reservoir pressures. Although such an artificial-lift mechanism dramatically boosts production rates, there are consequences on the quality of transient-pressure data in some cases. The paper presents the results of a thorough investigation of the behavior of pressure-transient data from horizontal wells equipped with ESPs in an oil field. Capturing the transient data without any distortion is important in estimating parameters of a horizontal well. This ensures establishment of all the important flow regimes on the log-log plot. But the early-time data suffers from distortion in buildup tests due to a very short period of hydrostatic balancing of fluids in the production string right after the ESPs are turned off. Drawdown data and rate transient analysis tools have been utilized to retrieve key well and reservoir information which might be missed in the early-time buildup data. Such integration is enabled by large sets of data from permanent downhole monitoring systems. Distortion of the early-time buildup data due to the falling liquid levels and some natural flow right after the ESPs are turned off for buildup tests consequently masks the early-time, vertical radial-flow regime. This distortion sometimes makes it impossible for unique estimates of the effective horizontal well length, the anisotropy ratio (vertical to horizontal permeability) and the damage skin. However, the empirical investigation shows that the early, vertical radial-flow regime develops in some drawdown tests with minor ESP effects. This drawdown data has been utilized to offset or reconstruct the flow regimes missed by the distorted early-time buildup data. In some cases, any low sampling frequency, low gauge resolution or lack of repeatability of the measured intake pressures at the ESP may hinder development of the early, vertical radial-flow regime in some drawdown tests. Note that a high sampling frequency and a high gauge resolution is required in capturing this flow regime. We have utilized rate-transient analyses to complement the pressure-transient analyses results whenever large data sets are available. The literature is devoid of any discussion on the challenges of interpreting the buildup tests on oil wells equipped with ESPs. This investigative paper with examples makes a comprehensive effort to understand such challenges. We have also shown ways to get around the problems and have provided reasonable interpretation of transient-test data.
- Asia > Middle East > Saudi Arabia (0.47)
- North America > United States > Texas (0.29)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Abstract The determination of optimum well locations and number of wells needed during green field development always comes with unprecedented challenges because of the geological uncertainty, and the non-linear relationship between the input and output variables associated with real reservoirs. These variables are key sources affecting the viability and validity of the results. Reservoir simulation is one of the least uncertain and most reliable prediction tools for dynamic performance of any reservoir. As field development progresses, more information becomes available, enabling us to continually update and, if needed, correct the reservoir description. The simulator can then be used to perform a variety of exercises or scenarios, with the goal of optimizing field development and operation strategies. Optimizing well numbers or locations under such geological uncertainty is achieved by using a reservoir simulator under several geological realizations, and these require multiple reservoir simulations to estimate the field performance for a given well configuration at a given location. Using reservoir simulation becomes impractical when dealing with real field cases incorporating multimillion cells because of the associated CPU demand constraints (Bouzarkouna et al., 2012). For instance, to determine the optimum well locations in a giant field that will result in the most efficient production rate scenario, one requires a large number of simulation runs for different realizations and well configurations. A large amount of runs is technically difficult to achieve even if we have access to super computers. The Fast Marching Method (FMM), which is based on solution of Eikonal equation, can be used to find the optimum well locations in a green oil field by tracking the pressure distribution in the reservoir. The FMM will enable us to calculate the radius of investigation or pressure front as a function of time without running any simulation and with a high degree of accuracy under primary depletion conditions. The main purpose of this paper is to study the effect of mobility on FMM and extend the investigation of its validity to include two phase-flow and convection-dominated flow and evaluate the ability of the methodology to predict the dynamic performance of the reservoir during pseudo-steady state flow regime.
- Europe (0.94)
- Asia > Middle East > Saudi Arabia (0.68)
- North America > United States > California (0.46)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Blocks 16/7b > Miller Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/8b > Miller Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- (13 more...)
Abstract This paper presents a well performance modeling approach to generate reservoir static bottom hole pressure (SBHP) data from on-stream oil well production data in wells completed with Electrical Submersible Pumps (ESP). The approach does not require shutting-in the well to obtain the SBHP as conventionally required prior to data collection. Hence, production losses are eliminated without compromising reservoir pressure surveillance. Recording downhole SBHP is an essential requirement for reservoir pressure surveillance as it provides significant information to evaluate reservoir inflow performance. SBHP data is used to generate the periodic isobaric maps, update the reservoir simulation models, and re-evaluate the applied injection strategy for possible adjustments when needed. Rigorous reservoir and wellbore performance analysis techniques were employed to generate accurate top-down reservoir pressure prediction models. The predictability of these models was statistically assessed on field representative samples of ESP completed wells with a wide-ranging operating parameters i.e. liquid rate, flowing wellhead pressure, water cut and reservoir pressure. In this modeling, ESP downhole sensors data were leveraged to reduce the uncertainty of the outflow performance models. A sample of 22 case studies from 4 different reservoirs was studied. These case studies were diligently selected to represent all ranges of operating parameters and reservoir pressure. Sensitivity analysis was performed on the well performance models to identify sources of uncertainty that can affect the model accuracy. Overall, this method has been proven to be widely accurate. The prediction performance of this method was found to be within 1.5% accuracy of actual pressure measurements.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Performance Analysis and Flow Regime Identification of Fractured Horizontal Wells in Tight Oil Reservoirs
Hui, Peng (Research Institute of Petroleum Exploration and Development, PetroChina) | Qiquan, Ran (Research Institute of Petroleum Exploration and Development, PetroChina) | Yong, Li (Research Institute of Petroleum Exploration and Development, PetroChina) | Min, Tong (Research Institute of Petroleum Exploration and Development, PetroChina)
Abstract Fractured horizontal wells are widely used to produce tight oil. But different fracture patterns could be generated in different reservoirs, which results in different well performances. How to identify the flow regimes and their impacts on performance is still challenging. This paper provides a method for flow regime identification of horizontal wells with different hydraulic fracture patterns in tight reservoirs. First, four different fracture patterns of hydraulically fractured horizontal wells in different types of tight oil reservoirs are classified, according to the fracture network identified from micro-seismic observation and laboratory experiments. Then, corresponding well performances are simulated based on various conceptual reservoir simulation models. The simulation results are further used for rate transient analysis. Finally, flow regimes and corresponding production periods of each pattern are identified and classified, and well performances are also analyzed. Flow regimes of different fracture patterns are identified based on rate transient analysis with input of reservoir simulation results. Different patterns have different flow regimes. For instance, there are linear flow, radial flow and boundary dominated flow in Pattern A, while bilinear flow, linear flow, radial flow and boundary dominated flow are prevail in Pattern C. The corresponding production phase of each flow regime is also classified. It can be seen that different scales of pores and fractures have different impacts on different patterns and production phases. In pattern A and Pattern D, large fractures determines the initial production rate and performance of linear flow, and more oil is produced in linear flow stage than in radial and boundary dominated flow periods. While in Pattern B and Pattern C, micro-nano fractures and pores are much more developed, which have more cumulative production and better performances during radial flow and boundary dominated flow. The results are applied to the tight oil reservoirs in Junggar and Erdos Basin in China. Analysis of all fractured horizontal wells indicates that most are pattern A and Pattern B, and linear flow occurs in the early production period in all the patterns. If hydraulic fractures are long enough, bilinear flow could happen. Well performances are correctly predicted based on the well flow regime identification.
- North America > United States > Montana (0.28)
- Asia > China > Shanxi Province (0.24)
- Asia > China > Shaanxi Province (0.24)
- Asia > China > Gansu Province (0.24)
First Time Live Descaling Operation in Saudi using Coiled Tubing Fiber Optic Real-Time Telemetry Rugged Tool, Foamed Fluid and Pressure Fluid Management System
Espinosa G, Mauricio A. (Saudi Aramco) | Leal, Jairo A. (Saudi Aramco) | Driweesh, Saad M. (Saudi Aramco) | Buali, Mustafa F. (Saudi Aramco) | Khnaifir, Waleed K. (Saudi Aramco) | Jasim, Ali J. (Saudi Aramco) | Noaman, Yousef M. (Saudi Aramco) | Sa, Rodrigo (Schlumberger) | Arifin, Mohammad (Schlumberger)
Abstract Saudi Aramco has long faced significant challenges to remove scales from the wells due to the high H2S contents and the sub hydrostatics reservoir pressure. Conventional techniques often fell short of expectations in the past, there had been cases of uncontrolled H2S releases at surface, which caused major HSE issues to the personnel; also coiled tubing (CT) got stuck due to sudden loss of circulation stemming from the inability to control the bottom-hole pressure and the instability of the fluid system during the scale removal treatment. As a result of those repeated issues, scale removal treatments were suspended for some time waiting for a safe technique to be devised. As a first step, the service company proposed to use a non-damaging chemical plug technique to temporarily plug the open perforations during the scale removal treatment, in an effort to avoid H2S release and to maintain circulation. The first results of this technique showed a marked improvement, which led the operator to resume the descaling operations, but in some operations the isolation process was extended several days and a large amount of fluid were injected into the formation, leading to induced damage, requiring high volume acid stimulation treatment and longtime flow back operation, to get the well back in production. To further optimize descaling operations via CT in Saudi Aramco, a novel scale removal technique was introduced that leverages the real-time downhole monitoring capabilities of CT equipped with fiber optics, to obtain a constant feedback on downhole conditions and allow swift adjustments to ensure safe operations. It also uses a redesigned foam system and implements a new pressure and fluid management system (PFMS), to eliminate the use of the temporary plug across the formation. With CT fiber-optic real-time telemetry, engineers can control the bottom-hole pressure throughout the intervention, to maintain the well slightly over-balanced and to prevent H2S from being released during fluid circulation. This system counts with a bottom-hole assembly (BHA) that gathers a full array of real-time sensors (pressure, temperature, casing collar locator, gamma ray, load measurements), and is compatible with downhole tools that require high flow rate to operate — in this case, a 2-7/8-in. turbine with a nominal flow rate of 2.8 bpm). This BHA can withstand a high level of shocks, vibrations and bottom-hole temperatures in excess of 300°F. As for the foam system, it ensures stable solid transport from downhole to surface conditions minimizing leak off into the formation, while the pressure flow management system (PFMS) is used to accurately control wellhead pressures, thanks to an array of auto chokes to control solid returns, and to remove entrained gasses (including H2S) from the returning fluid.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.98)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (4 more...)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks (0.82)