Even as the oil and gas industry looks for the next great idea to propel it forward, it should constantly reconsider past innovations for inspiration, the CEO of a major operator said Monday on the opening day of the 2017 SPE Annual Technical Conference and Exhibition. "The point is, you don't to have to go too far for new ideas," said Vicki Hollub, president and CEO of Occidental Petroleum Corporation. Hollub delivered the chairperson's luncheon speech on the first day of the conference, the key address underlining the 3-day conference theme. Hollub cited three technologies that, although not new, have played a significant role in upstream development not only when they were introduced but in the present day. Seismic imaging, horizontal drilling, and hydraulic fracturing all have succeeded in revolutionizing upstream practices over the years and even to this day, she said.
Reservoir modeling and the derived fluid production over time curves are a key part of the workflows associated with major capital project decisions. These models may be very complex and use a variety of geological constraints in an effort to develop the porosity, permeability, and saturation distributions used in dynamic models (with or without upscaling). Over time and partially in response to increased computing capability as well as the need for more realistically heterogeneous models, model size as measured by number of model cells and model complexity has increased but model-derived production forecasts remain optimistic. This paper, one of a series that now stretches back over a decade, addresses a number of modeling issues with the goal of (1) better understanding how modeling workflows may contribute to forecast optimism and (2) what reservoir modelers, both geologists and engineers, may do to reduce forecast optimism derived from their subsurface models by improved understanding of how model parameters such as grid size, number of grid cells, semivariogram parameters (e.g. the range), and number of geological/stratigraphic "control" surfaces used to constrain models. Adequate modeling of reservoir heterogeneity appears to require very to extremely large models (e.g. large number of small cells). Many of the parameters used to "control" heterogeneity including the semivariogram range parameter, the number of "detailed" stratigraphic layers, and the number of rock/facies "containers" or model regions appears to have only a small impact on forecast recovery.
Various methods that link a representative pore-throat size to permeability k and porosity ϕ have been proposed in the literature for rock typing (i.e., identifying different classes of rocks and petrofacies). Among them, the Winland equation has been used extensively, although when it was first proposed, it was based on experiments. Because of empiricism, the interpretation of the parameters of the Winland model and their variations from one rock sample or even one rock type to another is not clear. Therefore, the main objectives of this study are (1) to propose a new theoretical approach for identifying rock types that is based on the permeability k and the formation-resistivity factor F and (2) to provide theoretical insights into, and shed light upon, the parameters of the Winland equation, as well as those of other empirical models. We present a simple, but promising, framework and show that accurate identification of distinct petrofacies requires knowledge of the formation factor, which is measured routinely through petrophysical evaluation of porous rocks. We demonstrate that, although some rock samples might belong to the same type on the k-vs.1/F plot, they might appear scattered on the k-vs.-ϕ plot and, thus, could seemingly correspond to other types. This is because both k and F are complex functions of the porosity, whereas the porosity itself is simply a measure of the pore volume (PV), and does not provide information on the dynamically connected pores that contribute to both k and F. We also show that each rock can be represented by a characteristic pore size Λ, which is a measure of dynamically connected pores. Accurate estimates of Λ indicate that it is highly correlated with the permeability.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk.
Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Liu, Zhangcong (PetroChina Research Institute of Petroleum Exploration&Development) | Luo, Yanyan (PetroChina Research Institute of Petroleum Exploration&Development) | Fang, Lichun (PetroChina Research Institute of Petroleum Exploration&Development)
The foamy extra-heavy oil reservoirs in the eastern Orinoco Belt, Venezuela with high initial dissolved gas oil ratio and flow ability in situ, have been exploited by the Cold Heavy Oil Production (CHOP) method, with recovery of only 8%-12% OOIP. SAGD has proved to be one of commercially active post-CHOP processes. Whereas during the SAGD process the dissolved gas as non-condensable gas accumulated at the edges of the steam chamber causes a resistance to heat transfer between steam and oil, thus slowing down growth of the steam chamber and oil recovery. Therefore a novel SAGD process using alternate imbalance operating-pressure (AIOP-SAGD) is studied for the purpose of improving foamy oil SAGD performance.
The novel SAGD process involves multi SAGD well pairs, and with the growth of steam chambers, a significant pressure gradient is deliberately created between two steam injection wells. Moreover the higher and lower operation pressure of the two injection wells is periodically alternate. In this work, the potential evaluation and optimization of foamy oil AIOP-SAGD are studied, through extensive simulations utilizing a sector model, which is from a sector with representative oil and reservoir characteristics of Eastern Orinoco Belt, considering the mechanism of foamy oil and thermal recovery.
Simulation results indicate that the AIOP-SAGD process shows significant improvement in oil recovery, at least 10% higher than traditional SAGD. The mechanism includes two aspects: firstly the pressure gradient between two adjacent SAGD well pairs brings a sweep of dissolved gas from steam chambers; secondly, based on the flow ability of foamy extra-heavy oil, the pressure gradient helps to exploit oil between two SAGD pairs which is typically difficult to be recovered with conventional SAGD. The optimization of operating parameters shows that the optimal start time of AIOP-SAGD is when the oil rate of SAGD reaches the peak and the steam chamber extends to the top of the reservoir. High steam quality helps improve the performance of AIOP-SAGD. Moreover the parameters of alternate time, imbalance time, imbalance pressure difference were optimized.
ABSTRACT: Wellbore instability and formation sand production pose potential risks for wellbore drilling, completion and production operations. In many sandstone reservoirs worldwide, sand production has been observed to accompany oil and gas production. In this study, we aim to estimate, predict and quantify wellbore instability and sand production potentials in the Hajdúszoboszló field, Pannonian Basin, Hungary, using the Mechanical Earth Model (MEM). Our study relies on petrophysical log data obtained from an onshore gas well within the field as input data. Our 1-D MEM utilizes a workflow that develops wellbore and sand failure mechanisms, first creating the mechanical stratigraphy of the reservoir rock; followed by estimating the pore pressure, overburden stress, rock strength, rock elastic properties, and horizontal stresses of the reservoir rock with reference to the depth of stratigraphic column, from compressional slowness, shear slowness, density, porosity and shale volume. Lastly, we conduct a wellbore stability and sand management analysis. Our results show the mechanical stratigraphy of unconsolidated sandstone and shale distribution in the reservoir, wellbore shear and tensile failures, wellbore breakout and breakdown pressures, wellbore sensitivity analysis, sanding interval analysis, critical drawdown pressure (CDDP) profile and sand failure zones. Based on careful observation of our results, we predict the wellbore intervals with high sand production potentials and wellbore instability within the reservoir formations. Therefore, we suggest significant wellbore failure during drilling process and also a high possibility of sand production into the wellbore during well completion at a formation interval of 550-937 m. Although there is need for data from additional wells in the field to be incorporated into our model prediction, we suggest that our preliminary model can be useful for critical decision making during drilling and completion operations across the Hajdúszoboszló field, Pannonian Basin, Hungary. In addition, our study provides a platform for further investigation into wellbore stability and sanding analysis in other parts of the Pannonian Basin where available well data can also be incorporated in our model.
Brown, Joel (Chevron Corp) | Kumar, Raushan (Chevron Corp) | Barge, David Lee (Chevron Corp) | Lolley, Christopher (Chevron Corp) | Lwin, Al (Chevron Corp) | Al-Ghamdi, Saleh (Chevron Corp) | Bartlema, Ruurd (Chevron Corp) | Littlefield, Brian (Chevron Corp)
The 1st Eocene is a multibillion-barrel heavy-oil carbonate reservoir in Wafra field in the Partitioned Zone (PZ) between the Kingdom of Saudi Arabia and Kuwait. A large-scale steamflood pilot has been successfully completed in the 1st Eocene reservoir. The large-scale pilot (LSP) was the first multipattern steamflood in a carbonate reservoir in the Middle East, and consisted of sixteen 2.5-acre inverted 5-spot patterns with associated steamflood and production facilities. The primary objective of the LSP was to identify and mitigate technical and economic risks and uncertainties in carbonate steamflooding to assist in the broader Wafra full-field steamflood development (FFSFD) decisions. The key technical uncertainties related to the steamflooding in 1st Eocene reservoir were identified, categorized, and prioritized. These were then used as a basis to create surveillance and subsurface response plans. Success measures were developed to assess success in steamflooding this carbonate reservoir. These success measures were derived from the key metrics that were prerequisites for the FFSFD. The pilot met all the success measures, thereby mitigating the key technical uncertainties, and opened the path to FFSFD. This paper describes the elements of pilot planning and the results achieved during pilot execution. The emphasis, specifically, is on the achievements against the success measures set for the project; the insights into the pilot behavior from detailed analysis of production, pressure, and temperature data; and the progress made in identifying and mitigating key uncertainties in carbonate steamflooding.
Jafarov, Tural (Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (Fahd University of Petroleum & Minerals) | Al-Majid, Abdulaziz (Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (Fahd University of Petroleum & Minerals)
Reducing the filtrate volume and eliminating the solid invasion is very important and critical in drilling tight reservoir. This will eliminate water blocking which is the common problem in drilling tight gas formation.
The objectives of this study are to evaluate the effect of using sodium silicate, assess the changes of the rheological properties of water-based drilling fluid, determine filtrate volume and filter cake thickness, and optimize the concentration of sodium silicate to be used.
The obtained results showed that there was no effect of adding sodium silicate to the drilling fluid on density and pH. At room temperature, the optimum concentration of sodium silicate was 0.075 wt.% wt. which no change was observed in the yield point plastic viscosity ratio and at the same time, the plastic viscosity, yield point, and gel strength were enhanced. At higher temperature 120 and 170°F, the optimum concentration of sodium silicate was 0.075 wt.% which enhanced the rheological properties of the drilling fluid. Sodium silicate worked as a catalyst and as a result, it enhanced barite solubility at 200°F. The cumulative filtrate volume was decreased by 53% when using 0.075 wt.% of sodium silicate and the filter cake thickness was decreased by 65%. The retained permeability was 100% and the CT number before filtration and after removal was very closed, confirming no solid invasion was observed in the core.
In case of unconventional reservoirs, due to the complexity of drilling methods, formation damage by drilling fluids become more severe. The wells drilled for tight gas formations mainly suffers from water blockage problem. This is because of the much lower viscosity of gas than water, which water fills smaller pores of tight formation. Consequently, capillary forces cause water blockage.
There are several types of formation damage mechanisms. These mainly depend on composition and chemistry of drill-in fluid, used the bridging material, spurt loss characteristics of the drill-in fluid, the maximum level of overbalance drilling (Amanullah and Allen 2013). Ideal drill-in fluid should have degradable solids, minimum drill cuttings, reduced fluid invasion, not chemically reactive filtrate with formation fluid, filtrate that is not swellable with shale (Mandal et al. 2006).
Production of ultra-heavy oils is economically and technically challenging due to the very high viscosity of heavy oils, sharp viscosity increase over a small temperature drop and high operating costs. Reservoir oil can't even be mobilized by steam stimulation only due to inadequate reservoir energy. Even after the oils flow to the wellbore, the viscosity of the oils may exponentially increase when transported towards the wellhead due to the geothermal temperature decrease. The liquid oil could naturally turn into solid bitumen at any point where the temperature drops. The longer the travelling distance to surface for the oil, the bigger temperature drop, the greater the oil viscosity, and the more severe production challenges.
This paper presents the challenges associated with the production of ultra heavy oil in deep reservoirs in China. Operational difficulties widely exist in mobilization of in-situ oil, flow of oil from formation to wellbore, lifting of produced fluids from wellbore to surface, and surface processing and transportation of hydrocarbons. The sandstone reservoirs, sitting at a depth from 1600 to 1800 meters and having no support of any aquifer, contain approximate 4 million metric tons of 1.02~1.05g/cm3 heavy oil reserve. The oil-bearing formations have an average porosity of 27~29%, an average permeability of 1 Darcy and an original reservoir pressure of 16~17.5MPa. The oil viscosity at reservoir conditions (80°C) ranges from 6000 to 10000 centipoises (cP). Always keeping oil at a relatively low viscosity for feasible pumping is the theme topic with the thermal oil production in this type of reservoirs.
To find fit-for-purpose solutions, challenges had been analyzed in details for each part of the entire oil producing process covering the oil flow from the reservoirs to surface. The oil viscosity change with temperatures, the impact of oil viscosity reducers on the mobility of oil compounded with steam stimulation and CO2 injection for providing the initial energy to mobilize the heated oil, optimization of horizontal wells, screening of suitable wellbore lifting technology including wellbore heating and insulation and suitable chemicals for reducing the oil-water interfacial tension, and the steam stimulation optimization had been studied carefully prior to well drilling.
So far, 26 horizontal wells were drilled with an average of 130 meters horizontal section. Production data showed daily liquid rates at 800 tons at 55% water cut for all 26 producers after one year. The average peak oil production, the average cycle oil production capacity, the average cycle cumulative oil production of a single well was 25 metric tons per day, 14 metric tons per day and 2130 metric tons respectively. The average oil-steam ratio was 1.46 with a maximum oil-steam ratio of 5.26. The technologies discussed in this paper had been proved effective to produce ultra heavy oil from 1600 to 1800 meters formations with oil viscosity at 50°C conditions ranging from 180,000 to 260,000 cP.
Steam-Assisted Gravity Drainage (SAGD) is widely used in Alberta for recovering bitumen from oil (tar) sands. A variation of the same has had some success in heavy oils as well. It is a high-risk recovery method and requires careful planning and design. This paper outlines the success criteria for SAGD, and a design methodology.
First of all, applicability of other lower risk recovery processes, such as steamflood variants, is considered to determine if SAGD is a good choice. SAGD has been successful in oil sands of Alberta under rather restricted conditions. Geology is the most important factor, in particular vertical permeability, oil saturation, and initial mobility of water. Where the minimum criteria are not satisfied, there have been failures, discussed also. The author has developed new equations for the entire SAGD process, not just the stabilized oil flow regime, given previously, and has corrected the errors in the same. These are discussed in detail, with examples. The application of SAGD variations in conventional heavy oils is also considered.
The current experience in Alberta, and elsewhere, is described, and reasons for success/failure are outlined. Given that background, the desirability of SAGD vis-à-vis other thermal processes is discussed for California heavy oils. The variation of SAGD being employed in Saskatchewan heavy oils is also discussed, showing that it is not SAGD in the strict sense, rather a modified steamflood, using horizontal wells. It is concluded that SAGD has a high oil recovery potential if the right combination of rock-fluid properties is present. The application of SAGD to conventional heavy oils is equally problematic, in view of a very different mechanism.
The novelty of the paper lies in (1) a comprehensive treatment of SAGD, from the rising chamber to plateau to decline phases, (2) assessment of SAGD compared to other recovery methods for different types of reservoirs, and (3) application of SAGD variants to conventional heavy oils.