Heuman, W.R. (Phillips Petroleum International Corporation-Asia) | Moore, E.R.B. (Centrilift Division, Baker Hughes Oilfield Operations, Inc.) | Yue, Y. (China National Offshore Oil Corporation) | Hirshblond, S.P. (Pecten International Company)
W. R. Heuman,* Phillips Petroleum International Corporation-Asia, E.R.B. Moore,* Centrilift Division, Baker Hughes Oilfield Operations, Inc., Yue, Y., China National Offshore Oil Corporation, S.P. Hirshblond, Pecten International Company
Traditionally the operator and the supplier of ESP systems have not necessarily had the same goals and objectives with respect to maximising ESP run life. A longer run life means reduced costs and downtime for the operator while a shorter run life provides the ESP supplier with the opportunity for equipment sales.
This paper will describe the Quality Assurance Programme which has been implemented in the Xijiang Project to ensure ESP run life maximisation The Performance Based Contract that is being utilised between the operator and the ESP supplier will be addressed, as it is a key factor in providing the economic incentive necessary for the ESP supplier to strive to maximise ESP run life, Other key factors responsible for reducing the learning curve associated with ESP operations will be discussed. A summary of the results achieved and the conclusions reached from the implementation of the ESP Quality Assurance Programme will also be covered.
The Xijiang Development consists of two Fields, the XJ 24-3 and XJ 30-2, located approximately 80 miles southeast of Hong Kong in the South China Sea (Figure 1). Two production/drilling platforms set in a water depth of approximately 100 meters share a floating production storage and offloading vessel (FPSO) moored between the two fields. The Xijiang Fields are operated by Phillips Petroleum International Corporation Asia (PPICA). PPICA's co-venturers in the development are the China National Offshore Oil Corporation (CNOOC) and Pecten Orient Company.
The reservoirs in both fields are unconsolidated sandstone. The reservoirs are normally pressured and the drive mechanisms are aquifer support. The crude, ranging from 26-38 API, has a GOR of less than 20 scf/stb and has a very high paraffin content. The reservoir depths range from 1830 to 2750 metres with a BHT range of 175 to 240 F. Production rates of 4,000 - 14,000 BPD are anticipated from the various reservoirs.
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.
Generally, the reservoirs with permeability lower than 50x10-3 m2 is called low permeable oil field. Ansai oil field in which the average permeability is about l.29x 10-3 m2 is classified as ultra-low permeable oil field. Despite many low permeable reservoirs were discovered in early days, they haven't been effectively produced due to the complicated production technology and low profit. However, with the development of petroleum industry, the technologies of developing low permeable reservoirs have been improved, particularly, the progress of fracturing and water injection, the production of low permeable reservoirs has been rapidly developed. This paper aims to overview the reservoir, fracturing and water injection, describe the key methods used in production of Ansai ultra-low permeable reservoirs, including the results of water injection.
Ansai oil field is located in the west of China. It was found in l983.The oil-bearing series are placed in Yanchang group of Triassic system, including Chang 6, Chang 4+5, Chang 3 and Chang 2 layers. This is the largest integral oil field in Shan Gan Ning Basin up to now. The major oil reservoir named Chang 6 is at the depth of 1000 to 1300 m with the air permeability of 1.29x10-3km2(k=0.49x10-3 m2). So it is a typical ultra-low permeable, low pressure and production reservoir. There is no initial output when drilling in the oil reservoir with conventional mud. The formation productivity test shows that the production is below 0.3 to 0.4 t/d when drilling in oil reservoirs with unbalanced technique using oil-based mud or foam mud. After removing damage by conventional fracturing, the initial production is only 2 to 3 t/d and decrease to below 1.5 tons per day after half a year. Oil well is lack of fluid supply and intermittent pumping. The gas is escaped from the formation, wax and scale are seriously deposited in boreholes. So the pump efficiency is low. The surface environment is very complicated with inconvenient transportation. The production is difficult to manage. Because it is a marginal oil field, at the beginning of development, opinions vary to whether the production is efficient to obtain profit. In order to produce Ansai ultra-low permeable reservoirs efficiently, well group, pilot and industrialized test areas were opened to the study of reservoirs, oil reservoir production, completion, fracturing and water injection, so as to decrease drilling cost and greatly improve the effect of fracturing and water injection. The mechanical oil recovery, surface gathering and transportation and cluster drilling are matched. Ansai oil field has been put into industrialized development since 1990. At present, the average output of single well increases to above 4 tId from 1 to 2 t/d in water injected area. The plateau period has been up to 3 years.
At the present time, field-scale reservoir simulations are usually carried out with Cartesian grids. However, the use of these grids does not permit a good representation of reservoir geological features and reservoir description. Different approaches have been investigated to overcome the disadvantages of Cartesian grids. The corner point geometry (distorted grids) is often used as an alternative for complex full-field studies. This approach can better adapt the grid to reservoir boundaries, faults, horizontal wells and flow patterns and is easily used in standard finite difference reservoir simulators. The key problems for this technique are the preservation of the accuracy of fluid flow modelling and well treatment. In this paper, we will present a technique well suited to the corner point geometry and discuss its application range. Results are presented for test cases, comparing different control- volume type approximations.
In reservoir simulation, the use of rectangular grids associated with the standard finite difference method does not permit a good representation of reservoir geological features and reservoir description, especially for faults, cross stratified beds, heterogeneities and wells. Flexible grids, such as corner point geometry, triangular grids or Voronoi grids, can be used to improve the accuracy. Among these flexible grids, the corner point geometry is the most used with the advantage of easy implementation in standard reservoir simulators and of CPU time gain due to regular matrix structure.
The corner point geometry can represent complex reservoir geometries by specifying the corners of each grid block in grid building. It is well known that the use of the five-point scheme for distorted grids yields erroneous results. More accurate numerical schemes are needed with the ability to handle cross derivative terms. Several nine-point schemes, based on control volume methods, have been derived for distorted grids but no comparison is mentioned in the literature. These methods will be discussed in the paper and some examples are presented.
In addition to the description of geological features, another major application of flexible grid is well modelling. However, as presented by Ding et al., caution should be used as regards the well region gridding. A sophisticated grid may not give better results if radial flow is not well approximated. In this paper, we will present the techniques for handling well in distorted grids, independently of the well location within the grid block.
The technique of implementation in a 3-D reservoir simulator is also presented and some problems, such as heterogeneity modelling, are discussed.
This paper describes phase behavior simulation of complex process station in the light and volatile oil reservoir simulation, using equation of state method. The technology process of the station includes two-stage separation, crude oil stabilization, three-phase separation, shallow cooling, deethanization and debutanization. In the new compositional model, the simulation of surface complex process station is considered with combination of reservoir simulation based on uniform parameters of equation of state. The differential flash method and nested successive substitute iteration method have be used for solving dynamic phase equilibrium problem for deethanizer and debutanizer in the simulator. The simulator also considered process and product quality controls. The simulator provides calculation results for production of stabilized oil sale dry gas, light oil, naphtha and LPG. It is very useful for light oil and volatile oil reservoir simulation.
The compositional model is commonly used for light oil, volatile oil and gas condensate reservoir simulations, but conventional compositional simulators simulate surface facilities limited within multiple stage separation. In the development of light oil and volatile oil reservoirs in China, the complex process stations are used to be built for oil-gas separation and light hydrocarbon recovery process. Therefore it is necessary to develop a new kind of compositional model involving complex process station simulation.
There are two approaches for solving that kind of problem. One way is simultaneous simulation of surface facility and reservoir flow behavior in the same simulator. Another way is developing all independent surface facility simulator and using interface file to connect surface facility simulation with reservoir simulation. Easy way is last one, and we have accepted it. Although surface facility simulator is written as independent one, the programming inside configuration of the program and all called routines are conformed with main compositional reservoir simulator. We can look the new compositional model as a model consisted of three parts: initialization program, main model and surface facility simulator, which connected each other with interface files.
The existing offshore oil/gas fields in production in the Bohai Sea are all confronted with sea ice problems in the cold years. The development of a sea ice state warning system for the winter oil production in these fields is discussed in the paper on the subsidiary topics as: the skeleton of the system, monitoring and forecasting of the sea ice condition and the offshore structural behaviours, the criteria of warnings, and the database and software networks. The system is developed for various types of offshore structures and different oceano-geographical regions in the Bohai Sea.
Several offshore oil/gas fields including Chengbei, BZ28-l,BZ34-2, JZ2O-2 and SZ36-l fields in the Bohai Sea have been put into operation since 1980s, making a total output of 1.3 million tons crude oil and 500 million cube meters natural gas per year. Besides, there are other new fields such as : JZ9-3, Boxi and CFD-16-1 fields still in construction (Figure 1). Various types of offshore structures - jackets, jackup rigs, single point mooring (SPM) systems and artificial islands-are used in these fields, and they all may be standing in the drifting ice in such a cold winter as that in 1969. A drilling jacket and a flare jacket were totally pushed over by ice in 1969 and 1977, respectively. The JZ20-2 jackets were distressed by vibrations resulted from ice in the recent years, which gave influences on the offshore natural gas production and salo on the mind of the people working on board.
Wright, C.A. (Pinnacle Technologies Inc.) | Tanigawa, J.J. (Pinnacle Technologies Inc.) | Shixin, Mei (North China Bureau of Petroleum Geology (NCBPG)) | Li, Zhigang (North China Bureau of Petroleum Geology (NCBPG))
Economic gas production from coal seams (in which cavitation is not applicable) requires hydraulic fracture stimulation due to the low reservoir permeability of most target coal seams. Effective hydraulic fracture stimulation of coal seams, however, presents a formidable challenge due to a number of factors including: the mechanical complexity of coal; prevalent natural fracturing; extreme sensitivity of coal seams to fracturing fluid damage; stress sensitive permeability of coal; and the (often) complex geometry of the induced hydraulic fractures.
The authors began by performing an in-depth analysis of previous hydraulic fracturing treatments performed in coal seam reservoirs in China. The results of this post-treatment analysis, together with the collected reservoir data, led to the development of a modified stimulation strategy. As part of a pilot investigation by the North China Bureau of Petroleum Geology (NCBPG) of a (potentially) large coalbed methane field in China, eight hydraulic fracturing treatments were executed in the summer of 1994 using the modified stimulation strategy-- including on-site real- data three-dimensional hydraulic fracture modeling and treatment re-design.
This paper describes the analysis theory and methodology, the novel stimulation techniques employed, the on-site implementation (including difficulties), and the results of the fracturing treatments. While the paper is a case study of fracturing at a particular field, the paper will also contain a discussion of some of the complexities of coal seam fracturing. The issues to be discussed are: simultaneous propagation of multiple hydraulic fractures; (often) excessive near-wellbore fracture tortuosity; rapid downward proppant convection; and the high net fracturing pressures which may result in exceeding more than one of the reservoir's principle stresses.
Analysis of the collected data shows that 2-D models and "conventional" 3-D models of the hydraulic fracturing process apply very poorly to hydraulic fracturing in coal seams. Engineering decisions based on these more "conventional" fracture modeling techniques can lead to inappropriate fracture treatment design, as well as significant problems in predicting the post-frac production performance.
Ye, Feiting (Shengli Petroleum Administrative Bureau) | Sun, Jiancheng (Shengli Petroleum Administrative Bureau) | Wang, Baoxin (Shengli Petroleum Administrative Bureau) | Li, Hongwei (Shengli Petroleum Administrative Bureau)
In the last few years, the horizontal drilling technology in Shengli Oilfield has developed at a rather rapid pace So far, 30 horizontal wells of different types have been completed in various hydrocarbon reservoirs. This paper emphasizes the design and drilling practices in the horizontal exploratory wells and the horizontal development wells of viscous oil gravel reservoirs in Shengli Oilfield The application and technology of horizontal well to other oil and gas reservoirs are also presented.
Shengli Oilfield, the second largest oil and gas field in China, is a very important constituent part of Bohai bay oil and gas basin. Up to now, more than 20,000 wells have been drilled with accumulative oil production of 550 million tons. To stabilize the production, the urgent needs are to:
1. explore new reservoirs;
2. produce viscous oil;
3. produce residue oil from the old fields;
4. solve the water coning and production problems of low permeability reservoir. One of the best solution to the above is to drill horizontal wells.
Shengli Oilfield began drilling horizontal wells in 1990. By the end of 1994, 30 horizontal wells had been drilled in the four different oil and gas reservoirs of six areas, with total footage of 54,295m, and horizontal interval of 10,429m in length. In four exploratory wells, the productive zone of 673. 9m in thickness have been found. The horizontal development wells were penetrated through productive zones with horizontal length of 9,000m. The total production of the completed wells amounts over 300,000 tons. The daily production for single well is generally higher than that of the nearby ordinary wells in the same area. This paper emphasizes the design and drilling practice in horizontal exploratory wells and horizontal development wells in viscous oil gravel reservoirs.
HORIZONTAL EXPLORATORY WELLS
From September, 1990 to September, 1993, four horizontal exploratory wells were drilled in the Northeast Slope of Chengdong Oilfield The formations in this areas are very special; the top portion is Shahejie formation and Guantao formation of the tertiary system overlapping layer by layer towards the protruding upper part longitudinally; the pre-Sinian system formation to Mesozoic erathem formation below the unconformity surface monoclinally dipped to NNE direction and were covered by mudstone of Guantao group to Dongying group. In such way the Permian system to Mesozoic erathem unconformity reservoirs were formed (Fig. 1).
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.