Hazardous situations due to well control problems are not uncommon in exploration and production activity. Timely actions are of relevance when well conditions are time sensitive and in the presence of deteriorating situations.
In addition, precarious well conditions prevent you from taking wrong steps.
Small diameter packers and bridge plugs are often considered too weak to withstand particular environments, where pressure, temperature and mechanical stresses are present.
This paper discusses details of some utilization of inflatable bridge plugs and solid body bridge plugs, run with different techniques under limit conditions to overcome severe emergency well situations.
The case histories presented here describe recent actual case histories. They all occurred either in productive wells or in temporary abandoned, but still live wells, where the operational conditions required the intervention of specialized personnel, to overcome the critical situation. The same team of people has been working on the three cases presented here and, while for the first application, the selection of the equipment used, was forced by the contingent well situation, for the other applications performed the success gained on the first application had a considerable impact on the expected success of the others. The cases are not similar, and the only common factor is the harsh mechanical environment where the small diameter packers were run through.
SUMMARY OF THE INTERVENTIONS
1) Egypt '93 - Killing and well abandoning of a satellite platform sank by a cargo ship in the Red Sea.
The operation, performed by running a 2 1/8" inflatable circulating packer set in front of the casing perforations and conveyed by 1 1/2" coil tubing achieved the setting of the tool at 1798 m, after removing the collapsed mud line suspension piping and the reinstate to surface of the 3 1/2" production string. The most critical point, a ledge in the well tubular below the mud line, was passed in stripping and the inflatable packer was set at the required depth.
The hydraulic energy-storing workover rig is a new type of rig invented by the authors of this paper. The first experimental rig has passed through field test (see Fig. 1). This rig differs from other types of workover rigs not only in appearance but also in working principle.
There is an energy-storing system, so some energy issued from motors or from running down pipestring can be stored and used later when needed. This new invention has obtained a lot of advantages such as energy saving, safety, less noisy, possibility of using hydraulic tubing tongs without another hydraulic system, etc.
Nowadays, oil well workover rigs (or service rigs) are basically similar. Most of them are composed of engine, power transmission system, drawwork, derrick, crawn block, travelling block, etc.
During operations, the tubings, which weigh tens of tons, are putted down in the wells and lifted up from the wells repeatedly, consuming a lot of fuel. When a single or a stand of pipe are picked up from a well, the pure lift time is only about one third to one fourth of total time necessary for complete a circle of lifting a single or a stand. The rest of time is for auxiliary operations. But the equipped engine power should be large enough to meet the requirement in pure lift time. Powerful engine consumes more fuel even at idle or nearly idle working conditions.
Furthermore, when the pipestring is lowering down, the engine can not be stopped either, although the going down pipestring issues a large quantity of potential energy, which must be wasted uselessly by braking. How to raise the efficiency of rig, how to recover (even if only partly) the potential energy of pipestring? To solve these problems is the purpose and result of this invention.
The concept of energy-storing rig was completed in 1991. Later a feasibility study was taken place and the first experimental energy storing workover rig named XXJ 300/600 (see Fig. 2, 3) was designed and manufactured. Factory test and field trial were fulfilled in 1994. It is not easy to store motor power, especially to store and recover potential energy of pipestring, although partly, because of the energy which should be stored is intermittent and its volume is changed gradually at all time. For this reason, the rig has had a unique design.
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.
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.
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.
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.
The Johban Oki-2 well was drilled to a total depth of 4,984 m and reach of 3,881 m from the Iwaki platform located offshore Japan. Drilled and completed in 57 days during 1994, this well is believed to be the longest reach well in Asia.
The Johban Oki-2 was drilled by Teikoku Oil Company (TOC) with the assistance of Esso Sekiyu (ESK), Exxon's Japanese affiliate. This aggressive well was successfully drilled and completed using primarily conventional practices in directional drilling, casing designs and procedures, with selected application of state-of-the-art technologies, including:
1. Simulation of expected torque and drag, leading to selection of a catenary well profile and an aggressive friction-reduction program to permit use of standard 5-in drill pipe.
2. Drilling fluid formulation with an effective water-soluble lubricity additive to achieve the required reduced friction.
3. Wellbore stability analysis to specify the mud density and shale inhibition properties required with a water-based mud system.
4. Modeling of hole cleaning to ensure adequate hydraulics and cuttings removal.
5. Upgrade of existing ten-year-old rig with a portable top drive.
Recommendations from detailed well studies were implemented with excellent results. Wellbore friction factors were reduced as required, and torque at total depth (TD) was 40% below the value extrapolated from earlier drilling efforts. Wellbore stability and hole cleaning goals were achieved with all casing strings set as planned. All these factors contributed to finishing this record well 18 days (24%) ahead of schedule with only 9% non-productive time.
The Iwaki Gas Field was discovered offshore Japan in 1973. After feasibility studies from 1975 to 1981, a decision was made to develop the gas sands using a single platform. The Iwaki platform is located approximately 40 km offshore the east coast of Japan and about 200 km north of Tokyo as shown in Figure 1. This earthquake resistant platform was installed in 1983 in 154 m of water. During 1984 to 1985, fourteen wells were drilled from the platform into the gas bearing C-Sand structure from 2100 to 2200 m true vertical depth (TVD). Sea water/gel and sea water/gel/polymer muds were used with mud weights generally from 8.7 to 9.2 lb/gal; some lost returns were experienced with higher mud weights.
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.