Because of the unconfined nature of a steamflood pilot, its results cannot be extrapolated directly to a fieldwide project. Careful analyses of the pilot performance with consideration for fluid migration across the pilot boundary are needed for design and implementation of a successful fieldwide project. Large-scale simulation models that include both the pilot and surrounding patterns should be used for history matching the pilot performance, and the history-matched models used for design and implementation of a fieldwide project. As an approximation, a weighted average of confined and unconfined patterns in a project area as predicted from simulation or observed in the field can be used for designing a fieldwide project.
Steamflood projects typically undergo four phases of development: (1) reservoir screening, (2) pilot test, (3) fieldwide implementation, and (4) performance monitoring, analysis, and modification. After a steamflood candidate is chosen through reservoir screening, the technical and economic feasibilities of a fieldwide steamflood project are evaluated for the reservoir through pilot testing.
Pilot testing is perhaps the most crucial step in steamflood project development because it determines whether or not a large capital should be committed to carry out a commercial project. Many commercial projects followed successful pilot tests and yet, many others were abandoned because pilot tests showed that a full-scale project would be uneconomical.
In some situations, a decision to proceed with, or abandon, a full-scale project following a successful steamflood pilot, however, may have been based on incorrect interpretation of the pilot performance. There are many pitfalls in interpreting a pilot steamflood performance mainly because of the unconfined nature of a pilot that typically involves no more than a few steamflood patterns in a large area. Hence, a fieldwide project following a successful pilot may eventually turn out to be an economic future, while some of the projects that have not gone to commercial may still have the potential of an economic success.
This paper analyses the pitfalls in interpreting a pilot steamflood performance and discusses ways to avoid them. It recommends methods for accurately forecasting a fieldwide performance that should be used for deciding whether or not to proceed with a full-scale project. An accurate fieldwide forecast is also needed for designing and implementing the project if the decision is to proceed.
For long horizontal wells, the pressure drop along the well can exceed the drawndown between the wellbore and the reservoir. Therefore, it is very important to calculate the wellbore pressure profile with accuracy when determining the productivities of horizontal wells.
A comprehensive wellbore model, based on a transient, two-fluid approach, has been implemented in a general purpose reservoir simulator. The model can handle black oil, miscible, thermal, and compositional cases. The wellbore is represented by one dimensional finite-difference grid-blocks which are simultaneously solved with reservoir grid-blocks. A mechanistic model of multiple-phase fluid flow is employed to calculate flow regime identification, interfacial drag, and friction losses between the tubing wall and fluids. Phase changes and heat transfer inside the wellbore are also rigorously modeled.
Several horizontal well examples including the seventh SPE comparative project are studied. It is found that the production profile along the well can be very different between the cases with and without wellbore hydraulics. However, for most cases, the wellbore hydraulics impact on the ultimate oil recovery is minor unless the reservoir is poorly communicated within itself. In addition, we use the transient wellbore model to study the performance of a horizontal steam injector and the transient wellbore behavior of a shut-in well.
The use of the comprehensive wellbore model can be very time-consuming from the CPU standpoint, especially for extremely transient cases. For CPU time efficiency, we also have implemented a simplified approach to model the wellbore hydraulics, based on a steady state correlation. The phase changes and heat transfer inside the wellbore are neglected in the simplified approach. The results from this simplified approach are compared with those from the more rigorous comprehensive wellbore model.
In the past, the wellbore friction in the completion interval was generally neglected in reservoir simulators. Furthermore, as the wellbore physical properties, such as density, were computed from the previous time step production information, their values were not consistent with the calculated values of physical properties of the current time step. This may have caused the frequently-observed production oscillations after gas breakthrough in fine-gridded cross-section models.
For horizontal wells of one thousand feet or more in length, the wellbore friction cannot be ignored. The pressure drop due to frictional loss can be in the same or higher order of magnitude as that of the pressure drawndown between reservoir and wellbore completion. It thus becomes very important to model wellbore dynamics accurately.
Winterfeld did the pioneer work in coupling a two-fluid transient wellbore model with a reservoir simulator. He discussed the importance of the wellbore storage effect and the fluid redistribution due to phase segregation for multi-phase buildup well tests, Using this comprehensive wellbore/reservoir model, he was able to interpret abnormal pressure data.
Liu Xiang-E Research Institute of Petroleum Exploration and Development (RIPED) China
This paper presents the research, development and field application of the water control and profile modification technology in China. It discusses on the mechanism of chemical water plugging and profile modification as well as matching techniques and the economic benefits in oil fields application.
Since 80's, most of water flooding oilfield in China gradually step into the stages of moderate-high water cut. Previous technologies for early development stage of oil fields are no longer suitable for the present development of oil fields. It is critical and key technical problem to develop a new improved water flooding technology to stabilize and increase crude oil production in developed oilfields, for now and future. The aim of improved water flooding technologies is to increase the sweep efficiency and fluid production rate, length the stable oil production period and finally to increase the water flooding oil recovery efficiency.
The historical data during the production of sandstone and limestone reservoir demonstrate that water control and profile modification technology is one of the important techniques for increasing the sweep efficiency of water flooding.
From 50's to today, the research and application of water control and profile modification technology in China oil field experience three stages: the 1st, mechanical water plugging (from 50's to the later 70's); the 2nd, chemical water plugging (from the early 80's to the middle 80's); and last comprehensive treatment for profile modification in injector and water control in producer of blocks in oil fields (from the middle 80's to today). More than 20,000 well treatments have been carried out in oil fields from 1979 to 1993. The good production results from water control and profile modification have been achieved, such as the increase of recoverable reserves and oil production and decrease of water production and so on. The significant economic and technical benefit have been achieved. (see Table 1 and Figure 1).
PHYSICAL MODEL AND MATHEMATICAL MODEL STUDY OF POLYMER GEL PLUGGING AND PROFILE MODIFICATION MECHANISM
Using micro-model technology and nuclear magnetic resonance & imaging (NMRI), RIPED has studied polymer gel filling, immigrating and plugging mechanism in porous medium.
This paper discusses the design and application of the drilling and wellbore stability technology for an extended reach well drilled in the UK sector of the North Sea Central Graben Basin. The use of this technology can provide reservoir and development planners with an alternative means to economically and efficiently develop accumulations which are situated beyond conventional reach of drilling platforms. Very long reach drilling can enable developers to either defer or eliminate the capital spending associated with additional platforms and facilities or subsea development of satellite accumulations.
The paper addresses several areas that include mud weight and mud system, rock mechanics aspects impacting wellbore stability. well path design, drill string, casing and cementing considerations. It gives a detailed discussion of how the safe operating window for the mud weight was predicted from stability analysis and used to successfully drill the South Everest Extended Reach well (SEER T12) to TD. The paper also describes the rock mechanics data, in situ stress and pore pressure analysis. and operational practices trying to maintain the desired equivalent mud weight within the safe operating range.
This work originated with regard to a very long reach well drilled in the Amoco operated Everest Field. The Everest Field is part of a larger multi-field development in which several medium to small size gas-condensate accumulations, at a distance of 250 miles offshore of the UK, will be economically developed by sharing facilities and pipeline infrastructure created by Amoco and its partners (Central Area Transmission System-CATS). Everest Field consists of multiple accumulations spread over a wide geographic area and two production platforms situated in the northern and southern ends of the field are included in the development plans. Initially the north end of the field would be developed with the development of the southern end to occur at a later date.
During the development of North Everest, a very long reach well was conceived. which would be drilled from the North Everest platform at a lateral displacement of over 4 miles to reach the South Everest accumulation. This would defer construction of over $200 millions second platform and accelerate production. This well has been successfully drilled yielding a positive impact on project economics. The sail angle in this well reached 76 degrees by 5,300 ft measured depth. This angle was held resulting in a total displacement of 20,966 ft, a measured depth of 24,670 ft, and a 9,079 ft TVD, as shown in Fig. 1. The formation drilled was weak shale from surface to 8,000 ft TVD and shale/sandstone below to a Paleocene sandstone target at 8,900 ft.
The paper describes the key decisions, based on application of wellbore stability technology and associated rock mechanics study, which led to successful drilling of this South Everest Extended Reach (SEER T12) well. One of the most important aspects of planning such wells is deciding the correct mud weight from the wellbore stability analysis. The mud weights has to be high enough to prevent hole collapse but low enough to prevent fracturing the weak shale and production section. The rock mechanics and stability considerations gave the drilling team the confidence to reduce mud weight used earlier in drilling the production section by over 1 lbm/gal, which avoided differential sticking problems.
This paper offers a study of a new model of articulated downhole motor assembly for short radius horizontal drilling. Theoretical analysis of this model and relationships among acting forces, deformations, structure, borehole geometry and operating parameters are given. Design principles of the assembly configuration and main conclusions are also presented.
To meet the increasing demand of petroleum resources, since 1970's the short radius horizontal well drilling technology has been improved fastly. Now this technology has become the important technical way to enhance oil recovery of old wells.
Drilling tool is the key equipment in the drilling of short radius horizontal wells. Since 1930's, several companies have engaged in a series of research work and developed several kinds of short radius horizontal well drilling system. Hundreds of wells were then successfully drilled. Among the existing systems, the articulated downhole motor assembly is the most interesting one, because of its excellent technical performance and promising future development.
The articulated downhole motor assembly consists of a lower and an upper sections (Fig. 1). The lower section is a specially configurated motor assembly. It can be classified into two kinds, i.e. Angle-Build and Angle-Hold, depending on the application. The upper section is a flexible collar string connected by specially designed knuckle joints.
The function of the lower section is to drill the borehole (curved short radius section or horizontal section),while the upper one merely follows the curvature produced by the lower's and keeps the drilling continuously.
Although there are many published papers introducing the basic concepts, configurations and applications of the assemblies, the authors of this paper didn't find any one of them to deal with a mechanical constructions and its design principle. Very important theoretical works on the proper design of such assembly is to meet its engineering requirements. This paper, presenting the author's main works at mechanical analysis and design principle of the above mentioned assembly, may fulfill the deficiency in this domain.
HGEF, an oil/gas well stimulation technology by means of powder and/or propellant in well to create multiple radial fracture system in the vicinity of wellbore and hence to increase the well production, has been widely tested both home and abroad and shown a bright prospect in oil and gas industry. This paper deals with some fundamental aspects of HEGF, including technology base, key factor of HEGF, influence of HEGF on casing and cement, flow regime of the multiple radial fracture system and the relationship between charging, and pressurization. Based on the results of our researches and field applications, we hope that more attention should be paid to this stimulation technology.
Tracking back to the middle of 19th century, explosive stimulation was already applied to oil/gas wells to improve reservoir formation permeability iii the vicinity of wellbore and therefore to increase the well production. During the 1950s, well explosion, with maximum TNT consumption pf 1.0 toll to expand the wellbore diameter ten times larger, became a main stimulation technology in Yanchang oilfield located in western China. But the stimulation effect is not prominent. Experts in former Soviet Union studied the wellbore blasting process modulated also by one ton of TNT charge, and testified that the cavity diameter caused by the explosion was much larger than the original one and a compressing stress field remained near the cavity wall after the stimulation. This process established a compaction zone which obstructs the natural fissures, deteriorates the in--situ permeability, and is detrimental to the well production. Thereupon, using a multitude of explosive charge to stimulate the formation may be ineffective.
Further theoretical and experimental researches pointed out that a gentle controlled pulse process should be more suitable than a sharp explosive one. In other words, the stimulation effectiveness caused by the inflaming of gun powder and/or propellant will be more reliable than an explosive detonation process. As we know well explosion generates a pressure rising rate of about 106 to 104 MPa/S. But propellant merely with a pressure rising rate of about 106 to 107 MPa/S. The gap between them is three orders of magnitude at least, and this difference plays a crucial role in the advancement of the high energy gas fracturing(HEGF) technology which employs gun powder and/or propellant as its energy resource.
This paper presents the methodology applied to optimise the dynamic simulation of the giant Bu Attifel oil field (Libya) producing for 21 years under water injection.
When building the full field model of a giant field it is fundamental to limit the number of cells and CPU times without jeopardising the structural and sedimentological complexity of the reservoir. This will allow a correct simulation of future development phases, such as improvement in water injection (production-injection scheme optimisation, infill wells) and EOR processes (gas injection).
The first step of the study was the construction of two-dimensional cross sections based on the geological and dynamical data of the most representative wells. Then different oil displacement processes (water injection and gas injection) were simulated, mainly varying vertical communication and anisotropy of layers.
Groups of relative permeability pseudo functions, consistent with the different geological configurations, were used in the full field model to simplify and optimise the history match phase.
The complete reservoir study was aimed at optimising the future phases of the exploitation of Bu Attifel oil field by using a 3-D simulation model.
The numerical model had two ambitious targets:
- to respect the main physical properties shown by the field production performance,
- to simulate the behaviour of each single well as accurately as possible to obtain a reliable tool also for short term reservoir management.
This would require too large a number of computational grid blocks with very long CPU times.
The use of pseudo functions of relative permeability is a means of decreasing grid dimensions without compromising simulation accuracy. These functions scale up the results of laboratory core flooding experiments to macroscopic sand sections (full field model layering). Therefore, they take into account the effect of reservoir heterogeneity and gravity forces.
Gas reservoirs with abnormally high-pressure have 'been encountered all over the world. For these reservoirs, a straight line plot of P/Z Vs. Gp for the early production data and extrapolation to zero reservoir pressure project incorrect, IGIP, initial gas in place. The P/Z plot is based on the assumption that gas compressibility is the "Sole" reservoir drive mechanism. In abnormal pressure gas reservoirs, however, grain expansion, formation water expansion, and water influx from shale or small associated aquifer, in addition to gas expansion contribute significantly to the gas production. Several material balance models have been proposed to calculate the initial gas in place for abnormally high-pressure gas reservoir. The present study is concerned with analyzing the different material balance models used to estimate the IGIP for these kind of reservoirs. Therefore, it reviews the bases and assumptions on which these models have been developed, as well as discusses the strength and weakness of every model. In addition, the present study comprises calculations of the IGIP by analytical and numerical models of the material balance equations for eight case histories. The study shows that solution plot of Havlena and Odeh can be used to estimate the IGIP for abnormal pressure gas reservoirs without prior knowledge of the aquifer size or the formation compressibility. Moreover, the present investigation reveals that most of the material balance models analyzed in this study are sensitive to the value of the initial reservoir pressure and the early data. Unfortunately, this is the time when reliable estimate for the IGIP is vital for economic decision regarding the development of such gas reservoirs.
Over the last two decades increased attention has been focused on the analysis of reservoir reserve, behavior, and possible driving mechanisms important to the production from abnormal pressure gas reservoirs. These types of reservoirs have been encountered all over the world. They are also called superpressured or geopressured. They have initial pressure gradients greater then 0.6 psi /ft and can occur at any depth but mostly found at depths above 10,000 ft. Abnormal pressure gas reservoirs have high porosity, high water saturation, and found in shale/sand sequences. Some of these reservoirs are very small, drained by few wells, and sometimes associated with small aquifers that has not been detected on seismic studies. In the United States, abnormally pressured gas reservoirs are concentrated in the Gulf Coast, Anadorko Basin, Delaware Basin and Rocky Mountain Area. In the Middle East, over pressured reservoirs found in Iraq, Iran and Saudi Arabia. Over pressured reservoirs plus abnormally high temperature have also been found along the Red Sea Region.
Accurate determination of the initial gas in-place, IGIP, for gas reservoirs early in their production life is necessary in predicting future production and making economic decision regarding the development and production of such reservoirs. The industry standard method for the estimation of the IGIP for volumetric gas reservoir is the plot of P/Z Vs. Gp. This plot is used to estimate the IGIP by fitting a straight line thorough the early data and extrapolate to zero pressure. The plot is derived from the following equation;
In 1982 the Peoples' Republic of china awarded ARCO china Inc. the first-ever concession for offshore oil exploration by a foreign company. This historic event led to discovery of the 3 TCF Yacheng 13-1 gas field by ARCO China Inc. in 1983. This paper describes the US$1.1 25 billion Yacheng 13-1 Gas Project that will start-up in late 1995, some 12% years after field discovery.
ARCO's interest in the Peoples' Republic of China began with CEO R. O. Anderson's visit to Beijing in 1978, long before most companies had considered oil and gas exploration in the PRC. In the four years following Mr. Anderson's visit an area of interest was identified, geophysical contracts signed and seismic work undertaken in the South China Sea.
The 1982 exploration agreement with ARCO China and its partner, Santa Fe Minerals, was the first signed by the Peoples' Republic of China with any foreign company. ARCO China was designated as operator for the group composed of ARCO China, Santa Fe Minerals (later Kuwait Foreign Petroleum Exploration Company, KUFPEC) and China National Offshore Oil Corporation, CNOOC. The initial concession agreement provided for exploration of a 9,000 km2 area known as the Ying Ge Hai Basin, an area south of Hainan Island in the South China Sea.
In July 1983, the Yacheng 13-1 gas field was discovered with the drilling and successful testing of the Yacheng 13-1-1 well. However, the original exploration agreement signed in 1982 was for oil exploration, not gas, so negotiations for an amendment to the original contract began with CNOOC in late 1983. Confirmation of the Yacheng 13-1 field as a world class gas reservoir came with testing of the Yacheng 13-1-2 well in August 1984. After drilling additional dry or non-commercial wells in the concession area, a portion of the block was relinquished in 1985, resulting in the final development area shown in Figure 1.
In September 1985 a Supplemental Agreement was executed with CNOOC, this contract beginning efforts to commercialize the large 3 TCF gas reservoir. Development studies undertaken in 1986 focused on marketing the gas and condensate to Hainan Island and Guangdong province in southern China. However, this market failed to develop, and the last half of the 1980's saw little progress in the effort to monetize this large reservoir. During this period, however, ARCO China and its partners continued to pursue alternate markets.
Zhao, Hanqing (Research Institute of Petroleum Exploration & Development, Daqing Petroleum Administrative Bureau) | Fu, Zhiguo (Research Institute of Petroleum Exploration & Development, Daqing Petroleum Administrative Bureau) | Wang, Guangyun (Research Institute of Petroleum Exploration & Development, Daqing Petroleum Administrative Bureau)
A great majority of the productive reservoirs in Daqing Oilfield are composed of various kinds of fluvial channel sandstones. Under the condition of no outcrop, lack of analogous modern deposits available for detailed investigation, basing on the rich experiences of our research on reservoir sedimentary facies, as well modern fluvial sedimentological knowledge, a new research method is developed, that is, taking advantages of logging curves of close well pattern on a large area, and to gradually analyze sandbody geometries and their internal architectures, and to finely construct sedimentation models of fluvial facies reservoirs, and to describe reservoir heterogeneity finally. By applying this to subsurface reservoirs in large scale, four types of sedimentation models of fluvial channel sandbodies in PI1-3 zones are systemically constructed. Infill drilling and production test data have proved the credible accuracy and wide adaptability of the models.
The main productive reservoirs in Daqing Oilfield are a suite of large fluvial-delta deposits in the Songliao lake basin. Many kinds of fluvial channel sandstone reservoirs cover a fairly important proportion of reserves. They are developed in a great variety complicated geometries, different scales, and internal irregularities. Cutting and superimposing one another, and coexisting closely with sheet sands, the sandstones form intricate heterogeneous reservoirs. After a long period of waterflooding, most of the channel sandstones have entered a late stage of high water cut, but there is still considerable residual oil with complex distribution, so it is hard to find out and develop. To tap the potential of this part of reservoirs, a continuous production adjustment is carried out and many kinds of EOR projects are conducted. All of these need cooperation of detailed reservoir description in order that a good outcome can be obtained.
According to the special geological characteristics of Daqing Oilfeld, to construct detailed sedimentation models of reservoirs, which tallies with actual situation, are bases and keys to detailed description. This work is usually conducted first in outcrops or analogous modern deposits. Unfortunately, Daqing Oilfield has no its owner analogous outcrops, and lacks detailed investigation data of modern deposits either. What we can do is only to start with subsurface data. For thin interbedded alternating reservoirs, present seismic data can do nothing with them. Under this circumstance, relying on our research experiences in the study of reservoir sedimentary facies, and fluvial sedimentological knowledge, after repeated practices, a new method to construct detailed sedimentation models of fluvial facies reservoirs is found out after using close spacing logging curves on a large area. By applying these research thoughts to substance in large scale, four sedimentation models of fluvial channel sandbodies are constructed.