The PDF file of this paper is in Russian.
High gas and sand production along with productivity decline are amongst some common well management challenges in oil producers of Azeri-Chirag-Gunashli (ACG) field in the Azerbaijan sector of the Caspian Sea. This paper will focus on trials in the region in deploying chemical treatments to tackle excessive gas and sand production in unconsolidated reservoirs.
Sand production can disrupt normal operations at topside facilities, cause well management challenges and well productivity impairment. Successful sand shut-off (SSO) also means some financial and safety risk reduction for the business.
Reservoir pressure support through secondary recovery mechanisms is an important component for delivering production targets of ACG field. With continuation of gas injection for reservoir pressure support, the Gas Oil Contact (GOC) can move closer to the producers at times resulting in well management challenges due to rising well Gas Oil Ratios (GORs). Upon free gas breakthrough (GBT), well drawdowns are actively restricted to prevent further growth in gas rate and subsequent acceleration of oil rate decline. For some wells, an effective Gas Shut-Off (GSO) would mean immediate production impact associated with increased drawdown available potential. In others, the driver for GSO is the need to minimize total facility gas production volumes to avoid immediate or future production deferrals due to gas facility constraints. In sand producing wells, successful GSO interventions provide the secondary benefit of reducing risk of flow-line and choke erosion that arise during well life.
Various mechanical and chemical techniques have been assessed and deployed in trials to mitigate high gas and sand production in ACG over the last four years. The objective of this paper is to share the candidate selection methodology and results of the chemical GSO and SSO trials implemented to date. In addition to this overview, the surveillance data supporting the candidate selection process will be presented with pre and post intervention well parameters to demonstrate the impact of the shut-off techniques along with longevity.
Multi-finger caliper tools are widely used for inspection of casing inner wall condition, particularly for determining wear, corrosion, deformation and scaling. The maximum pipe wall penetration, and hence metal loss, inferred from this method is greatly dependent on the casing inner diameter value (provided by casing manufacturer) used as a reference. Evidence of overestimated casing wear, including new completions, has raised the question around the validity of such interpretations.
Most of the casing is manufactured to API 5CT (ISO 11960) standard. The manufacturer‘s specification has an associated tolerance on casing outer diameter and thickness that is then used in the multi-finger caliper logs interpretation. The tolerance for casing with outer diameter (OD) greater or equal than 4.5″, is between -0.5% and +1% of OD. The pipe wall thickness tolerance ranges between manufacturer's nominal thickness and 12.5% metal loss.
The calculation of casing internal diameter (ID) tolerance is a difficult task as this is controlled by the casing mass tolerance which in practice is not easy to measure. To overcome the challenge, we implemented a new approach of calculating the minimum and maximum casing inner diameter and then using the ID tolerance as a reference for multi-finger caliper logs interpretation.
This approach has been tested with field data, and shows good correlation to actual casing inner diameter measurements performed at surface and is used as a baseline for new casing strings.
This paper will describe in detail the approach taken and compare the difference between interpretation outcomes with and without using the casing inner diameter tolerance. The benefits of calculating casing inner diameter tolerance and applying it to multi-finger caliper log interpretation results will be backed up with evidence from field log data acquired in ACG.
The PDF file of this paper is in Russian.
Petroleum Experts Integrated Production Modeling (IPM) toolkit is widely used in Tengizchevroil (TCO) for short and long term production forecasting in the Tengiz field. The short and long term models each have their own strategic focus. The short term IPM model is used for day-to-day management of field activities to ensure business plan production volumes are delivered. The long term IPM model is used to manage base business and optimize scenarios for various future development projects. The short term IPM model is validated and history matched continuously and forms the basis of the long term model to meet business objectives.
Because of the complexity of the Tengiz gathering system, close collaboration among multiple teams, systematic updates and continuous improvement of the model is required. It is also important to have an accurate temperature prediction across the entire field network to conduct flow assurance studies, optimize plant inlet temperatures and maximize plant throughput.
As a result of the implemented calibration efforts, the model predicts field production rates within 1% of the actual field performance. The model provides more granularity and higher confidence in ensuring that the plant can produce at its maximum capacity when wells are shut-in for surveillance activities, pipeline repairs and meter station (MS) shutdowns for gathering line repairs. In a long term perspective, it's crucial to have an accurate model to plan MS shutdowns for upgrades and the successful startup of major capital projects.
This paper describes model improvement initiatives, the best practices and lessons learned during the calibration process of the complex IPM model. A structured workflow for the calibration of the IPM model is also provided. The calibration steps are described in detail with relevant examples throughout the paper. This workflow can be used by IPM practitioners in other fields to construct and maintain integrated production system models.
It is common to observe thin oil zones with limited thickness between the gas cap and the bottom water in gas-condensate reservoirs. The existence of thin oil zone must be taken into account in the development plan of the gas-condensate reservoirs, as this nuance has a significant influence on the recovery factor of reservoirs.
The objective of this paper is to understand the influence of thin oil zone to the development of the gas-condensate reservoirs in the South Caspian Basin. A numerical 3D hydrodynamic reservoir model has been built and sensitivity analysis has been performed for different reservoir properties. The results of the cumulative gas and condensate production were studied in terms of the reservoir total recovery factor to show the impact of different reservoir properties.
According to the results, it is crucial to study and understand the thin oil zone in gas-condensate reservoirs, as the presence of thin oil zone increases the reservoir recovery. Even not produced separately, the thin oil zone has positive influence on the development of gas-condensate reservoirs.
Additionally, the sensitivity study shows that the properties such as the reservoir absolute permeability, the thickness of the oil zone, the aquifer strength, the critical gas saturation, the critical water saturation and the residual condensate saturation have an essential influence on the final results even if the thin oil zone exist in the gas-condensate reservoirs. From the reults, it can be inferred that, although the thin oil zone has a positive impact on the gas-condensate reservoir recovery, the above mentioned properties also must be investigated and taken into account.
Jinfang, Wang (RIPED, PetroChina) | Zhengmao, Wang (China Natl. Petroleum Corp. Tian Changbing) | Jun, Tian (China Natl. Petroleum Corp. Tian Changbing) | Chengfang, Shi (RIPED, PetroChina) | Jian, Gao (RIPED, PetroChina)
The PDF file of this paper is in Russian.
This paper depicts the laboratory results as well as reservoir surveillance and well production performance of microbial flooding in Fuyu oilfield, China. A four-spot water flooding has been applied from 1973, and various measures to increase production has been implemented since 1981. However, 1/3 non-absorbing reservoir and the invalid circulation of injection water lead to low production rate, high water cut, big flooding difference and low sweep efficiency.
To reduce water channeling, the Microbial Enhanced Oil Recovery (MEOR) test was initialed in Fuyu oilfield, China, in 1992. A microorganism named CJF-002 fed on nutrient was discovered as huff-puff test from 1996~2001. To replace the nutrient with high cost, a new nutrient was developed, using cornstarch as main raw material from 2002~2004. Furthermore, multi-slug microbial flooding was conducted at 22 injection-production well groups in 2005. The cell count of CJF-002 was more than 10^7cells/ml, and injection pressure less than 10MPa. The concentration of CJF-002 and crude oil composition in the sample was analyzed in laboratory before and after MEOR. Moreover, injection profiles monitoring and tracer tests were compared. Finally, the results of laboratory and tests were contrasted with well production performances.
The results observed microbial propagation under reservoir conditions with temperature 30°C and PH 7.5. The effect of injection profile modification was confirmed, which was helpful for plugging the high permeable zones and reducing water channeling. The agreement is obtained with the well production performances. Among them, 87.3% wells indicated a 50~100% oil production increase and an 8% water cut decrease. The water-drive laws curve shows the characteristic of drop, which means the improvement of development effect. The tests show that the composite indigenous microorganism oil displacement technology can enhance the oil yield of mature oilfield and recovery ratio, and it is an effective stimulation measures.
Currently, a significant quantity of oil fields all over the world are developed with reservoir pressure maintanance mechanisms.
It is worth noting that sometimes water is injected into a reservoir with pressure, which is higher than the rock pressure. Such condition causes technogenic autofracture opening in productive layer. The autofracture is not strengthened with a proppant, so its geometrical size changes with the change of bottomhole pressure. And this feature leads to some difficulties with injection well work regulation.
An attempt to explain the reasons of ineffective well operations (bottomhole treatment and outflow profile alignment) on several fields of West Siberia was an occation for these studies. We found a considerable number of examples on these fields, where well operations had opposite results than were expected. So, we have hypothesized the causal link existence between holding ineffective well operation and the presence of autofracture in this injection well. For this aim, first of all, we describe the algorithm for autufracture detection in injection wells with the help of Bourdet diagnostic plots (which are used in well test interpretation) in conjunction with field data. Then, we checked our hypothesis by studying a statistic correlation between well operations with opposite result and autofracture presence. Finally, we show an explanation how opposite results of well operations in injectors with autofracture can be easily explained. The reason is rather obvious, but this phenomenon have never been described before: all the matter is in ratio between bottomhole pressure and pressure of autofracturing before and after well operation.
Based on these results, we made a clear conclusion about the necessity of considering possibility of autofracture appearance in injection wells. Also we will give some recommendations about work regulation for injection well with such feature.
As part of Dunga oil field water flooding program, well injectivity impairment analysis through series of core flood laboratory experiments was conducted with the primary objective to ascertain reservoir plugging possibility of the solids/fines contained within injection water that comprises combination of Produced Water (PW) and planned Caspian Sea Water (CSW). The quality of water and its compatibility as re-injection fluid requires investigation to ensure considerations from a reservoir management perspective are built into the facility water handling design criteria.
The scope of this study utilizes industry standard workflows of core flood experiments customized to suit required conditions using real CSW and PW samples. The later stage of the analysis uses various combinations of synthetic brine representing compositions of PW and CSW covering various levels of turbidity. The use of synthetic brine enables varying water filtration standards to be applied/simulated, and to determine the impact of individual elements on formation damage / permeability degradation.
Based on observations, CSW Core flood tests do not exhibit plugging/formation damage effect. This implies that formation fines migration or clay swelling in low saline water environment is not an issue for the Dunga field. Furthermore, the relatively low volume of total suspended solids (TSS) and low fluid pH index explain no detrimental impact of its injection into the tested core plugs.
Variation of total suspended solids content in injection water imparts significant damage to the tested core plugs. PW Core flood with high TSS shows instantaneous severe plugging with drastic permeability degradation. Whereas, PW Core flood with low TSS displays slight (tolerable) level of plugging that could be partially restored by chemical acid treatment. When CSW and PW blend is injected into formation, no fluid compatibility issues were observed. Instead, the plugging potential of the mixed injection water is diluted via increasing CSW content which contains lower TSS volumes.
All key findings related to real water samples have been ratified with synthetic brine experiments that helped identify an impact of individual water property on deliverables. Recommendations for injection water filtration scheme for the Dunga field were delivered as a result of this study which should positively impact the ultimate recoverable volumes of the development.
Shtun, S. Y. (LUKOIL-Nizhnevolzhskneft) | Senkov, A. A. (LUKOIL-Nizhnevolzhskneft LLC) | Abramenko, O. I. (LUKOIL-Nizhnevolzhskneft LLC) | Matsashik, V. V. (LUKOIL-Nizhnevolzhskneft LLC) | Mukhametshin, I. R. (RESMAN Rus LLC) | Prusakov, A. V. (RESMAN AS) | Nukhaev, M. T. (Siberian Federal University)
The PDF file of this paper is in Russian.
The purpose of this paper is to compare the permanent monitoring systems based on optical fiber systems and intelligent chemical tracers. This analysis was carried out based on an operational assessment of similar systems for permanent monitoring of horizontal wells in the Yuri Korchagin oilfield for 3 years in various regimes of operation.
The paper discusses the main advantages and limitations of these systems and provides their comparison to conventional production logging tools (PLTs).
Mingqiang, Chen (China University of Petroleum) | Linsong, Cheng (China University of Petroleum) | Renyi, Cao (China University of Petroleum) | Chaohui, Lv (China University of Petroleum) | Jiuzhu, Wu (China University of Petroleum) | Hao, Liu (China University of Petroleum)
The PDF file of this paper is in Russian.
Due to intensive heterogeneity and micro-nano-meter-scale pores in tight formation, flow mechanism differs significantly from that in conventional reservoirs. Therefore, the capability to simulate pore scale flow in tight formation is of great importance in many applications, such as oil extraction from tight reservoirs and accurate prediction of oil production. In this paper, a 3D random network model which can characterize the heterogeneity of tight formation is proposed. Based on the established network model, a flow mathematical model in consideration of boundary layer effect is developed, whereas parameters in boundary layer thickness formula are determined by Particle Swarm Optimization algorithm. Then, repeated iterations are used to solve the flow mathematical model until the relative error of pressure in each pore between two adjacent iterations arrives at the given error, which guarantees the accuracy of the simulation result. The result is then validated by micro-tube experiment. Furthermore, factors influencing pore scale flow in tight formation are studied. Results show that: as a result of boundary layer effect, absolute permeability is no longer a fixed value, it increases with the increase of pressure gradient and reaches a stable value when displacement pressure gradient is large enough. In low displacement pressure gradient, non-linear flow appears. As average coordination number increases, connectivity of tight formation becomes better, absolute permeability and velocity are larger at the same pressure gradient; When pore radius remains unchanged, as aspect ratio increases, throat radius becomes smaller, effective space for fluid flow is compressed, leading to smaller absolute permeability and velocity at the same pressure gradient; Change of 3D random network model size through varying throat lengths has little effect on pore scale flow; With the increase of fluid viscosity, boundary layer becomes thicker and the effective flow space grows smaller, resulting in lower permeability and velocity at the same pressure gradient. When displacement pressure gradient is large enough, absolute permeability tends to a stable value, which has nothing to do with fluid viscosity.
Kurimov, Dauren (Tengizchevroil) | Lim, Kok-Thye (Tengizchevroil) | Urazmukhambetov, Berik (Tengizchevroil) | Kairbekov, Amirbek (Tengizchevroil) | Rojas, Danny (Tengizchevroil) | Kassenov, Baurzhan (Tengizchevroil) | Aitkazin, Mirkhat (Tengizchevroil) | Rey, Alvaro (Chevron ETC)
Due to its complex nature, long term development scenarios have been modeled using a subsurface reservoir centric model, with representative surface constraints such as well head pressure. Near term operating plans, on the other hand, have been based on a detailed surface network model that included a comprehensive representation of plant, flowlines and operating conditions. Each of these models have been calibrated and their accuracy were verified independently.
We have recently implemented a fully coupled reservoir-surface network model consisting of complex surface network, including three processing plants, and two subsurface reservoir models. The model is run using a controller which manages the surface network model running on a PC and the reservoir model running on a Linux cluster.
The coupling modeling approach in long term forecasting becomes essential when the field deliverability is impacted by the dynamic conditions in the surface facilities. The coupled model provides critical insights when major changes are introduced throughout field life, such as major surface facility expansion, surface network depressurizing, differing regional depletion rate in the reservoirs.
This paper presents the advantages and challenges of applying the coupled model in a complex surface gathering system network being fed by several subsurface reservoirs with different pressures. The model provided insight on the detailed and complex interaction between the subsurface reservoir and the surface network, which cannot be achieved using either standalone model (surface or subsurface). The information enabled us to identify opportunities for debottlenecking and optimizing production through management of back pressure in the system.