Ali Dogru, SPE, Saudi Aramco Fellow and chief technologist at EXPEC Advanced Research Center, and SPE John Franklin Carll Award winner was elected to the US National Academy of Engineering. Dogru was elected for his outstanding achievements in the “development of high-performance computing in hydrocarbon reservoir simulation.” He is internationally renowned in this field, having published more than 100 technical papers and having earned several patents. During his career with Saudi Aramco, Dogru conducted field simulation studies and led the development team for the company’s first Parallel Oil Water Enhanced Reservoir Simulator (POWERS) in 2000. In 2010, a team under his leadership released the industry’s first billion-cell reservoir simulator, GigaPOWERS.
Oil price is a determinant factor in many economic equations. The consistent growth of oil demand indicates the importance of petroleum products in the economic growth of both developing and developed countries. The new market conditions after the introduction of the shale oil and the extent of its influence on determining the oil price indicates a requirement for new oil market models that include new parameters. In this paper, based on the system dynamics methodology, we provide an updated model of the supply and demand of the oil market to explain the market trends. Our model provides the causal relations between the major components of the market including the determinants of the supply and demand. We divide the supply into the OPEC, non-OPEC and US producers. Further, we have extracted the supply of Iran, Saudi Arabia, Libya, Venezuela, and Iraq in the OPEC, and Russia and Syria in the non-OPEC categories in order to be able to further detail the effects of specific events that influenced their corresponding productions. We also provide a detailed case study of the major market events after 2010 that have had consequences on the oil market. Finally, we train the model with the 2014 and 2015 data and simulate and validate the model for 2016 to support our model's performance.
Spyrou, Charidimos E. (Schlumberger) | La Rosa, Andres Pieve (Schlumberger) | Khataniar, Sanjoy K. (Schlumberger) | Uzoechina, Frank (Wintershall Holding GmbH) | Awemo, Kilian N. (DEA Deutsche Erdoel AG)
A pattern flood management method based on a streamline simulator was developed to support waterflood designs. The methodology was applied on a structurally complex oil field in the North German basin. Studies are being conducted to understand the potential for extending the current waterflood in this oil field. The objective of this study was to investigate if a conventional simulation-based waterflood design could be enhanced using streamline simulation.
An alternative to using streamline simulation could be the post-processing of streamlines based on outputs of a full-field finite difference (FD) simulation model. However, there are limitations to this approach, including robustness and time considerations, especially when multiple runs with field-scale reservoir models are required. The streamline simulator contains a pattern flood management algorithm designed for optimizing the performance of waterfloods using multiple value criteria. The algorithm continuously balances patterns during forecasting runs converging to optimal injection and production rates while honoring well and field production constraints. A unique set of pattern performance diagnostics are ancillary products, for example pattern efficiencies and leakage fractions.
The full-field FD dynamic model of the aforementioned oil field was adapted for the streamline simulator. Both simulation models delivered similar results at the field and well levels and matched historical observed data satisfactorily. The best pattern flood model converged on a rate schedule that led to a 4% increase in oil production, a 17% decrease in water production, and a 5% reduction in the water injection volumes over the best performance achieved using a conventional voidage replacement strategy in the FD model. These findings were validated by executing the full-field model on a FD simulator with the recommendations from the pattern flood simulation run. The streamline simulation runs executed about seven times faster. To investigate the well count optimization potential, rigorous analyses were performed on the pattern information produced by the enhanced runs. A 12.5% reduction in well count, in terms of injectors and producers, could be achieved, and the pattern flood management algorithm converged on a rate schedule that still led to an increase of 2.3% in oil production, a 22% decrease in water production, and a 10% reduction in injection volumes.
The streamline-based simulation study proved useful in improving the existing waterflood design. Speedup in runtime allowed ample investigations and analysis within a given time period. Detailed analysis of allocated rate schedules and pattern information across numerous forecast runs gave deeper insight on the problem. The study highlighted that any well pattern has associated with it an optimal rate-scheduling strategy. Hence, the two components are important aspects of any successful waterflood design. The recommended rate schedules are model based and hence subject to uncertainty, requiring updates as additional information becomes available over time.
In this study, a review of production performance of four existing horizontal producers equipped with Inflow Control Device (ICD) completions was conducted using 4-D dynamic modelling on a sandstone reservoir with high water mobility. The aim of this study was to investigate the optimum regulation degree across ICD completion i.e. the ratio of pressure drop across ICDs to the reservoir drawdown, suitable to delay water breakthrough, minimize water cut and achieve production balance.
A single wellbore model was built by populating rock and fluid properties in 3-D around the wellbore for each of the studied wells. The model was then calibrated to the measured production log flow profile and bottomhole pressure profile for the deployed ICD completion in each well. Thereafter, several ICD simulation cases were run at target rates for a production forecast of 4 years. An optimum ICD case for each well was selected on the basis of water breakthrough delay, water cut reduction and incremental oil gain.
The study results showed that there is a correlation between reservoir heterogeneity index, well productivity index (PI) and optimum regulation degree required across ICD to achieve longer water breakthrough delay and better water cut control. In general, high heterogeneity, high PI wells require higher regulation degree across ICD of close to one; medium heterogeneity, low PI require regulation degree across ICD of between 0.3 – 0.45 while low heterogeneity, low PI, require very low regulation degree of between 0.1 – 0.15. Based on study results, a new ICD design framework and correlation chart were developed. This framework was then applied to two newly drilled horizontal producers to test the applicability of the workflow in real time ICD design scenarios and positive results were achieved.
Given the significant number of ICD completions deployed yearly, this new ICD design framework would provide guidance on how much pressure drop across ICD is required during real time design for newly drilled or sidetrack wells and would ultimately ensure maximum short and long term benefits are derived from deployment of ICD completions.
Xu, Yandong (Research Instittue of Petroluem Engineering, Sinopec North-West Branch) | Pang, Wei (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Instittue of Petroluem Engineering) | Li, Shuanggui (Research Instittue of Petroluem Engineering, Sinopec North-West Branch) | Zou, Ning (Research Instittue of Petroluem Engineering, Sinopec North-West Branch) | Du, Juan (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Instittue of Petroluem Engineering) | Mao, Jun (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Instittue of Petroluem Engineering)
Shunnan Block in North-West China is one of the toughest HPHT gas reservoirs with vertical depth over 7500 m, formation temperature over 200 and pressure gradient varying from 1.3 to nearly 2. The condition is close to temperature and pressure limit of well testing tools, therefore, the tools are hard to be sent to downhole and chances are that well testing operations usually failed. The pressure buildup data are with bad quality and needed to be converted into downhole data. Meanwhile, it's hard to diagnose accurate flow regimes and interprete because the block is typically carbonate reservoirs with porous medium including pores, natural fractures and caves.
In this paper, we reviewed the exploration wells in this block and find that interpretation by pressure buildup or transient production data can only reflect part of the formation information; therefore the two kinds of data are combined to get more accurate interpretation results. For pressure buildup interpretation, three models including dual porosity model, composite model, and dual porosity with composite model are chosen and compared. For the production data, dual porosity model with boundary is selected because the wells usually show characteristics of multiple porous medium and boundary dominated flow. Parameters interpreted from pressure buildup data are simultaneously transferred into the model for production data.
Results show that the combined interpretation by pressure buildup and production data can reduce the un-uniqueness of models as well as enhancing the accuracy of formation and wellbore parameters evaluation. The model and parameters can satisfy both pressure buildup and production data history. Although Shunnan block is considered as one greatly promising reservoir from the short period open flowing, the combined interpretations suggest very limited drainage volume. Reasons for this paradox phenomenon may be that the wells are severe contaminated by drilling fluid, or the wells were only producing gas in caves and natural fractures nearby the wells while other caves are not connected.
An ensemble-based 4D seismic history matching case is presented. Seismic data are re-parameterized as distance to 4D anomaly front and assimilated with production data. The field is a large turbiditic system, with initial fluid pressure close to the bubble point. Production causes the pressure to fall below the bubble point, resulting in a widespread gas-exsolution. The time-lapse change in gas saturation is considered responsible for the observed negative relative changes in seismic velocity seen over the all reservoir. This study is innovative for two reasons. First, the distance-to-front parameterization is applied to the gas-phase which appears everywhere in the field, rather than coming form an injection source like in previous application of the parameterization. Second, the binarization of the simulated time-lapse anomaly is performed circumventing the use of a petroelastic model; the petroelastic model would be necessary to relate the measurements to fluid properties changes and to decide a threshold for binarizing observations and pressure. However, the effect of gas is so widespread and evident that the petroelastic model is replaced by a clustering approach based on the gas saturation change of the reservoir cells. This study shows that adding the 4D re-parameterized seismic data in addition to the production data is keeping a reasonable match with production data while constraining the overall gas distribution in the reservoir to the observed seismic data.
A detailed sensitivity analyses was conducted on an analog simulation model of a hydraulically fractured shale gas well to assess the effects of various controlling parameters on gas rates throughout the production life. Differentiating operational parameters from reservoir properties facilitates high grading shale gas exploration play evaluation and provides guidance to optimize gas production, and manage uncertainties associated with reservoir properties for predictive forecasting. The sensitivity analyses suggest that early-time gas rates are primarily dominated by the characteristics of stimulated rock volume (SRV), while late-time rates are controlled by reservoir properties. The learnings from sensitivity analyses were applied to predict production rates and estimated ultimate recovery (EUR) for a shale gas well in the KSA with flowback data. Early-time wellhead pressure data is very likely controlled by the effect of transient liquid loading and wellbore dynamics, and, as such, may mask the actual reservoir pressure response. While history matching the flow-back period may reduce the uncertainties associated with the quantification of SRV, wellbore dynamics, and initialization, large uncertainties in the estimates of reservoir properties remain the same. This reduces the confidence in predicting long-term production.
Al-Ansari, Adel (Saudi Aramco) | Parra, Carlos (Saudi Aramco) | Abahussain, Abdullah (Saudi Aramco) | Abuhamed, Amr M. (Saudi Aramco) | Pino, Rafael (Saudi Aramco) | El Bialy, Moustafa (Halliburton) | Mohamed, HadjSadok (Halliburton) | Lopez, Carlos (Halliburton)
A properly designed reservoir drilling fluid and precise control of its properties are essential to prevent formation damage issues that hamper production. An essential prerequisite for a reservoir drilling fluid are nondamaging specialty products and reduced fines and fluids invasion. This paper describes the case history of two deep gas wells in Saudi Arabia, one well showed impaired production due to screens plugging and was put on workover drilling operations whereas the other well was a regular development well. The offset data showed differential sticking, partial losses and tight spots while drilling the 8⅜ and 5⅞ in. hole sections.
The well reservoir data including the bottom hole-temperature – 300°F, permeability – roughly 10 to 20 micron pore throats and lithology – sandstone intercalated with shale, for the reservoir section were determined from offset analysis. Extensive lab testing was performed with nondamaging specialty and optimized PSD for minimized fine and fluids invasion. This engineered fluid was used to drill a 5⅞ in. vertical side track of ± 300 ft for the workover well whereas on the regular development well about ± 400 ft of the 5⅞ in. section was drilled. The fluid was continuously monitored for PSD at the rig along with the particle plugging test for fluid loss control. The hole cleaning and equivalent circulating density was monitored and programmed with a proprietary hydraulics software. All the fluid properties were determined to be within planned range. The wells were drilled without any of the offset problems as discussed above followed by running the 41/2 in. conventional sand screens to the bottom without any issue. Initial flowback production testing was performed on the workover well, which took 8 hours as compared to the usual 48 hours in the offset wells. The BS&W (basic sediment and water) from day 1 of production was 9% as compared to the 25% observed in the offset wells. The gas production rate was 200% more than was expected as per the offset information.
This paper shows the successful use of reservoir drill-in fluid on two gas wells: one was a workover well and another a regular well. The abstract presents a mutual approach between Halliburton and Saudi Aramco to address the issue of minimizing formation damage and mitigating differential sticking. Offset well data learnings, optimized PSD design, monitoring at the rig site, and the use of nondamaging specialty products delivered production optimization.
In Kuwait, the traditional approach to Field Development has been to drill wells, whether Vertical or Horizontal, Single or Dual, with completions dedicated to either Production or Injection. However, as increasingly more wells are being drilled to develop the stacked reservoirs, surface infrastructure is growing in complexity with regard to Production Flowline routing, Gathering Facility location, Satellite Manifold placement, Water Injection distribution lines routing, and access road construction. Also, since the reservoir stack is a combination of areally extensive Carbonates overlying shale & channel sand sequences, optimum surface locations of Injectors for one reservoir is now increasingly conflicting with the optimum surface locations for the Producer of another reservoir.
The North Kuwait team presented options that could reduce the requirement for excessive wellbores for both new Producers and Injectors. One of which is the utilization of a single wellbore to both Produce Oil from one reservoir and Inject Water into another reservoir simultaneously. This novel approach utilized the most popular Dual Completion equipment, but rather than produce or inject concurrently from separate reservoirs or layers, production & injection are achieved simultaneously through either tubing string. Tubing movement calculations were made to ensure that the resultant axial tubing forces exerted by simultaneously injecting cold water and producing hot reservoir fluid would not cause the Dual packer to prematurely unset.
This unique completion has several advantages which include the production acceleration from an adjacent reservoir/layer that would have been postponed for the life of the Injector and the elimination of the drilling of a new producer to access the oil from an adjacent reservoir/layer to the target injection zone. Additionally, the elimination of the drilling of an Injector well if its optimum subsurface location is close to, or coincides with, an existing Producer from an adjacent layer, and the reduction in access road construction and location preparation costs. This strategy will significantly reduce Unit Development Costs while concurrently ramping up production levels. With simple conversion workovers, rather than drilling new wells, Oil Production potential that is presently unexploited in dedicated Injector wells can immediately be realized. Pressure support Injection can be initiated as soon as distribution injection lines are made available via similar conversion workovers.
Al-Houti, Naser (Kuwait Oil Company) | Al-Othman, Mohammad (Kuwait Oil Company) | Al-Qassar, Khalid (Kuwait Oil Company) | Al-Ebrahim, Ahmed (Kuwait Oil Company) | Matar, Khaled (Halliburton) | Al Hamad, Abdulla (Halliburton)
This paper presents the application of a unique gelling system for perforation shut-off operations that can help reduce operational time by 50% and can also be used as an effective water- and gas-migration control agent. The system combines a conformance sealant (based on an organically crosslinked polymer) with non-cementious particulates. The particulates provide leak-off control, which leads to shallow matrix penetration of the sealant. The filtrate from the leakoff is thermally activated and, as a result, forms a three-dimensional (3-D) gel structure that effectively seals the targeted interval after exposure to the bottomhole temperature (BHT).
The traditional method for recompleting wells into newer layers, after the current producing zones have reached their economic limit, involves several steps. The first step is to squeeze off the existing unwanted perforations using cement, drill out the cement across the perforations, and then pressure test the squeezed zones to help ensure an effective perforation seal has been achieved. The new zones are then perforated and completed for production. The entire operation can require four or more days of rig time, depending on the success of the cement squeeze. In cases of cement failure, the required time can extend to over one week. Common challenges associated with cement-squeeze operations include leaky perforations, fluid migration (gas or liquid) behind the pipe, or compromises in the completion. Attempts to remediate these issues must be repeated until all objectives are met.
The new perforation plugging system can be bullheaded into the well (spotted at a desired location in the wellbore), allowing for easy placement and calculation of the treatment volume. The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion, which allows for future re-perforation of hydrocarbon-producing zones. The system can be easily washed out of the wellbore, unlike cement, which must be drilled out. The temperature range of the particle-gel system is 60 to 350°F, which makes it versatile.
To date, more than 500 operations have been performed with this system globally. This paper presents the results obtained from laboratory evaluations, the methodology of the treatment designs, and four case histories from Kuwait. A salient case is the successful use of the sealant/particulate system, resulting in shutting off all perforations after six failed cement-squeeze operations.
The prospect of reducing the required time to perform remedial cement-squeeze operations by 50%, as well as the ability to repair casing leaks and seal off thief zones, make this sealant/particulate system a valuable alternative to standard cement-squeeze operations.