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).
Severe heterogeneity of continental sandstone reservoir has set great difficulty for understanding and smoothly developing oil field. But can we make effective adjustment at late period of high water cut stage making use of this characteristics? Daqing oil field has made useful attempt, including developing new technologies to deepenly tap the two sides potential of thin, poor and thick reservoirs through fine reservoir description; conducting development adjustment in old area by taking advantage of various differences in oil field development caused by heterogeneity to realize oil production replacement and maintain oil production stabilization at the level of relatively high annual oil production; fluid production and water cut increase rate are also effectively controlled, opening up a new way of maintaining oil production at late period of high water cut stage, and obtaining considerable economic benefits. Practice proves that this set of methods are novel in thought and feasible economically, and can promote the development of reservoir description and developing technology. So systematic introduction is presented here just for reference for the same type of oil fields.
By the end of 1990, Daqing oil field has been developed for 30 years, recovering more than 60% of the recoverable reserves, the comprehensive water cut of La, Sa, Xing oil reservoirs as the mainbody of Daqing oil field has been to 80.23%, entering late period of high water cut stage. At this time, according to experience of the test of small space injection development conducted in 60'S in Daqing oil field, the increase of fluid production index and fluid oil ratio of oil wells will dramatically accelerate, and oil production will decrease rapidly (Fig 1.2), producing degree of reserves deepens, primary adjustment of strata of series whose main target is low permeable reservoir has basically been completed. Targets of the ongoing secondary infill drilling would be the low permeable thin reservoirs in which residual oil scatter in a high degree and the ultra-low permeable reservoirs in which oil immersion and oil patch are main occurrences and whose geologic reserves are not calculated (we call it "untabulated reservoir"), single infilling well production and controlled recoverable reserve will also decrease dramatically(Fig3); as the increase of water cut of old wells, the oil stimulation result of each measure also decrease annually.
Facing this difficulty, can we continuously realize high and stable oil production through effective adjustment in old area to meet the needs of national economy to oil production?
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.
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.
A wax deposition scale-up model has been developed to scale-up laboratory wax deposition results for waxy crude production lines. The wax deposition model allows users to predict wax deposition profile along a cold pipeline and predict potential wax problems and pigging frequency. Consideration of the flow turbulence effect significantly increases prediction accuracy. Accurate wax deposition prediction should save capital and operation investments for waxy crude production systems.
Many wax deposition models only apply a molecular diffusion mechanism in modeling and neglect shear effect. However, the flow turbulence effect has significant impact on wax deposition and can not be neglected in wax deposition modeling. Wax deposition scale-up parameters including shear rate, shear stress, and Reynolds number have been studied. None of these parameters can be used as a scaler. Critical wax tension concept has been proposed as a scaler. A technique to scale up shear effect and then wax deposition is described. For a given oil and oil temperature, the laboratory wax deposition data can be scaled up by heat flux and flow velocity. The scale-up techniques could be applied to multiphase flow conditions.
Examples are presented in this paper to describe profiles of wax deposition and effective inside diameter along North Sea and West Africa subsea pipelines. The difference of wax deposition profiles from stock tank oil and live oil is also presented.
When transporting a waxy oil through a cold pipeline, wax will be deposited on the cold pipe wall through molecular diffusion and shear dispersion mechanisms. Many wax deposition models only apply molecular diffusion mechanism in modeling, but neglect shear effect. However, our previous results6 show that the flow turbulence effect has a significant impact on wax deposition and can not be neglected in wax deposition modeling. The shear effect on wax deposition is difficult to interpret with correlations or dynamic equations. A semi-empirical technique is proposed to scale up shear effect and then apply conventional modeling techniques to predict wax deposition for waxy crude production lines.
When transporting a waxy oil through a cold pipeline, wax will be deposited on the cold pipe wall through molecular diffusion, shear dispersion, Brownian and settling mechanisms.
REFLOATING MAUREEN OIL PLATFORM (110,000 TONNES)
FOR REUSE IN WATERS AWAY FROM THE NORTH SEA
The Maureen Oil Platform located in Block 16/29 of the UK continental shelf, North Sea has been in operation since September, 1983.
The fields that the platform serves are now nearing the end of economic production life and the operator, Phillips Petroleum Company United Kingdom Limited and its coventurers now have to decide how to most effectively abandon and dispose of the facility.
The platform is a three structure. Each of the cylindrical steel oil storage the seabed. tank steel gravity three "legs" is a tank which sits on the seabed.
The platform utility and process plant is installed on the main deck, the lower deck and on a mezzanine level. There are five decks of accommodation and office modules sited on the main deck.
The three cylindrical storage tanks are normally fully flooded with water, crude oil or a combination of both, depending on the frequency of export to the offtake tanker. The tops of the storage tanks are at an elevation of 74 m above the seabed.
The platform is unique in its design, being the only steel gravity based structure in the North Sea.
The depth of water in which the platform stands is 95.6 m at L.A.T.
The platform was floated into location, already complete, and ballasted into position. In order to meet disposal regulation and international law its most likely removal will start with the entire platform being refloated.
As a free floating mobile platform it is available for use in any other waters of the world, subject to environmental and soil conditions.
This paper will demonstrate the work that has been carried out (and is continuing) to verify the refloat and marine stability of the platform as a vessel under tow.
The paper summarises a conceptual study carried out by AGIP for the development of offshore marginal heavy oil fields in the Adriatic sea (Italy).
On the basis of this study a comprehensive R&D programme was started, in order to validate the innovative technologies proposed.
The considered field size, with OOIP in the order of 80-140 million of ST bbl and the quality of the oil with a gravity around or less than 10 API, makes the conventional production schemes economically non viable.
The paper discusses some alternative development schemes based on the following innovative technologies.
1- Fluidification and transportation of heavy oils via oil-water dispersion;
2- Artificial lift of heavy oils with jet pump by using water as motive fluid:
3- Multiphase pumping of the produced oil-water emulsion, from platform to shore;
4- Light, reusable, unmanned platform.
A comparison of the principal economic indicators of the innovative proposed solutions versus the traditional ones is presented. The new production schemes allow development of offshore heavy oil fields with costs saving of as much as 30 %
During the past 20 years several exploratory and appraisal wells were drilled in the Central Adriatic Basin. The result of this intense drilling activity was the discovery of several marginal oil fields (fig.1). The quality of the oil with gravities ranging between 6 and 14 API, a sulphur content of 6-8% in weight and the size of the fields (5 - 20 millions barrels of recoverable oil from each field) hindered their development because of the poor economic return of the investment.
For the two best fields, named in this paper "first field" and "second field", prefeasibility studies for the development were carried out in the second half of the 80's.
The solutions proposed at that time for both the fields were similar: a production platform connected by a flowline to a nearby FSU (Floating Storage Unit) for the storage of the produced oil. The FSU was a converted tanker permanently moored at about one mile from the platform and the export of the oil was foreseen by shuttle tanker. The fluidification of the oil was foreseen by kerosene.
PRODUCTION SCENARIOS WITH INNOVATIVE TECHNOLOGIES
The two alternative scenarios for the development of the two fields were selected after a screening study embracing 20 different solutions.
Luo, Pinya (Southwest Petroleum Institute) | Li, Jian (Southwest Petroleum Institute) | Niu, Yabin (Research Institute of Petroleum Exploration and Development of CNPC) | Zhang, Daming (Research Institute of Petroleum Exploration and Development of CNPC) | Xui, Tongtai (Drilling Administration, China National Petroleum Corp.)
This paper presents the design and the field application of amphoteric polymer mud system to solve the problems conventional polymer caused, when drilling high reactive shale formation. It has been studied relationship of the structural features and mechanisms of polymer molecules with the performance of polymer mud. Amphoteric polymers have been developed with cationic and anionic groups in the one polymer molecule chain to be the dual function to improve the inhibition and to maintain excellent rheology of mud. This new kind of polymer mud system has been utilized in most oilfields of China, in diverse geographic locations, formation lithologies and hostile environments such as high density, high salinity and high temperature. It has been observed in the fields that this new drilling fluid has the desired optimum shale and borehole stabilization, improved rheological properties, high rates of penetration and benefit for oil formation protection.
Unlike other mud systems, polymer mud properties are controlled by water soluble linear type polymer (acrylate polymer and partially hydrolysed polyacrylamide). Clay particles can be adsorbed and bridged by this type of polymer to form a special structure in mud, which shows the shear thinning property. Even at low solid content, high viscosity can be obtain at low shear rate and low viscosity at high shear rate. High drill rate, solids-carrying capacity, hole clean and reasonable distribution of drilling hydraulic power can also be obtained. On the other hand, high molecular polymer can adsorb on shale formation, encapsulate drilling cuttings to inhibit the dispersion of the shale formation and the disintegration of cuttings, which improve the borehole stability, as a result, the low solid content and low clay dispersion can be obtained in the mud.
The two kinds of characteristic of polymer in mud are closed relative each other, so that how to obtain the better rheological and inhibitive properties is an important polymer mud technology.
Laboratory tests and field application shown that enhance inhibitive properties of a polymer mud can improve shale formation stability, reduce cuttings desperation, limit formation damage and more important action is to control a excellent rheological properties and maintain low solid content in the mud. The research and application in China and abroad focus on enhancing mud inhibitive property and improving mud rheological properties to suit hostile drilling conditions.
Palmer, Ian (Amoco) | Vaziri, Hans (Technical University of Nova Scotia) | Khodaverdian, Mohamad (TerraTek) | McLennan, John (TerraTek) | Prasad, K.V.K. (Amoco) | Edwards, Paul (Amoco) | Brackin, Courtney (Amoco) | Kutas, Mike (Amoco) | Fincher, Rhon (Amoco)
Ian Palmer,* Amoco, Hans Vaziri, Technical University of Nova Scotia, Mohamad Khodaverdian,* TerraTek, John McLennan,* TerraTek, K. V. K. Prasad,* Amoco, Paul Edwards,* Amoco, Courtney Brackin, Amoco, Mike Kutas, Amoco, Rhon Fincher, Amoco
Amoco is producing coalbed methane from several hundred wells in both San Juan and Warrior basins. These wells were completed/stimulated in one of two ways: (1) openhole cavIty completions. (2) hydraulic fracture stimulations through perforations in casing. cavity operations are described, and new data from several cavity completions is presented and analyzed. The latest geomechanics modeling of the formation of cavities in coalbeds is presented. The model allows the growth of a cavity as tensile failure occurs, and computes increases in permeability in a stress-relief zone that extends tens of feet from the well. critical parameters are given for the success of cavity completions. A pulse interference analysis is discussed: as well as interwell permeability, this can provide information on stress-dependent permeability. Finally, some wells which were originally cavitated did not perform up to expectation, and have been recavitated with remarkable success - these are also examined.
Amoco has tried several different kinds of hydraulic fracturing treatments. Results of comparisons between foam fracture, slick water fracture, and gel fracture treatments are presented. Statistical comparisons are given for regions outside of the fairway zone in the San Juan Basin. In the Warrior Basin, water fracture treatments with and without sand have been compared. Lastly, foamed water cleanouts, without sand, have been deployed, and their success is reviewed.
In this paper we present new information on completions/stimulations of coalbed methane wells. Specifically. we discuss (1) openhole cavity completions in the fairway (sweet spot) of the San Juan Basin (Colorado and New Mexico - see Figure 1), and (2) fracture stimulations in the San Juan Basin and the Warrior Basin (Alabama).
The openhole cavity completion has been used with tremendous success in the San Juan Basin. Some wells produce in excess of 10 MMCFD from only 3,000 ft depth in the fairway zone (Figure 1). In the cavity operation, a series of injections (or shut-ins) and blowdowns (actually, a controlled blowout) is performed over typically a two-week period. Coal fails and sloughs into the wellbore and is ejected from the well, leading to creation of a cavity (enlarged wellbore). A plastic or shear failure zone is also formed beyond the cavity. and in this region the permeability is changed.
A typical Amoco cavity operation was described previously. Below is an elaboration of certain aspects of cavity operations in the San Juan Basin fairway:
1. The openhole portion of the well is generally 200-300 ft in height, containing usually more than 50 ft of net coal. The coals are divided into the basal coals, which are usually the more productive, and the upper coals. Normally 7-in. casing is topset above the top coal, and TD is only a couple feet below the bottom coal.
2. A typical cavity operation entails a sequence of (1) cleanout of the well in the evening using air (1,500-2,200 SCFM) and water (20-100 BPH) injections, followed by (2) flow testing lasting typically four hours, followed by (3) cavity operations (or CST), typically 6-10 surges during the daytime. Before the flow test and CST, the bit is either pulled into the casing shoe or to the surface. The sequence is repeated many times over typically 10-20 days.
3. All flow tests are conducted through a 3/4 in. choke, typically for four hours. All pressure surgings are conducted by rapidly opening a surface valve, allowing gas and water and coal fines to be expelled through blooie lines to the pit.
4. The basal seams seem to respond more than the upper seams to the cavity operations, presumably because they are more friable.
5. It is not uncommon to see 0.5-1 in. pieces of coal come to the surface during cavity operations.
6. In flow tests in good wells, flows during the cavity operations often decrease with time over 1-4 hrs. This may be the transient effect that is predicted by the cavity modeling (see later in this paper).
Coal is not an inert reservoir rock and reacts to gas desorbed from its surface. Coal matrix shrinks as gas is desorbed, increasing cleat width and, therefore, permeability. Very few coal matrix shrinkage data have been reported in the literature so a series of experiments was undertaken to measure such data at reservoir pressures, temperatures, and 100% relative humidity. Strain gages were affixed to the coal sample in the face and butt cleat directions as well as the vertical direction. This work reports measured deformations of a sample of high volatile C bituminous coal from the San Jan Basin during sorption and desorption of first methane then CO2. A pressure cycle was also run with helium, a nonsorbing gas, to determine mechanical compliance of the sample. Observed strain gage behaviors are discussed and shrinkage coefficients for both gases reported. Matrix shrinkage was found to correlate with gas content rather than pressure, confirming the work of a previous investigator. Shrinkage coefficients varied more among replicate gages aligned in the same direction than between gages in different directions. Anisotropic shrinkage effects are discussed. Using a matchstick geometry model, equations are derived for permeability change due to matrix shrinkage. Coefficients reported here are used in example calculations of absolute permeability and porosity increases during coalbed depletion.
Coal matrix swells and shrinks as gas is first adsorbed then desorbed. The amount of swelling depends on coal rank and sorbed gas composition. During recovery of coalbed methane, coal matrix will shrink, increasing cleat width. As permeability depends on the cube of cleat width, a small increase in cleat width may significantly increase permeability. Such an increase will offset permeability losses due to increased stress during depletion.
A search of the literature revealed eight previous studies of coal matrix shrinkage.14 These studies are summarized in Table I. The matrix shrinkage coefficients ranged from a low of 8.62E-7 psi-1 to a high of 6.55E-4 psi-1. Moffat and Weale investigated sorption induced swelling of low volatile bituminous and semi-anthracite coals. They determined a methane swell in coefficient of 1.70E-6 psi-1 at a pressure of 200 atm. Gunthe investigated swelling due to methane and carbon dioxide on coals with ranks ranging from high volatile A to anthracite. Reported swelling coefficient ranged from 2.76 to 6.90E-6 psi-1 and carbon dioxide was reported to swell coal more than did methane. Vinokurova found low rank coals swelled more than high rank coals but no swelling coefficients were reported. Wubben, et al., investigated swelling of anthracite and bituminous coals and reported swelling coefficients of 1.4 to 6.9E-6 psi-1. Reucroft and Patel used coals from the Appalachian Basin of the USA to investigate swelling due to sorption of carbon dioxide, nitrogen, and xenon. They reported a carbon dioxide swelling coefficient of 6.55E-6 psi-1. Gray measured a methane swelling coefficient of 8.62E-7 psi-1 for a Japanese coal of unreported rank. No details of coal rank were provided by Juntgen when he reported a methane swelling coefficient of 2.57E-4 psi-1. Only one of the previous studies, Harpalani and Schraufnagel, dealt with a coal currently of interest to coalbed methane recovery. Using a sample of Piceance Basin coal, they reported a shrinkage coefficient of 6.2E-6 psi-1. Unfortunately, many of these studies were done at pressures below those typically encountered in CBM fields and none of them used reservoir temperatures or the high humidity conditions typical of in situ coals. Nor did any provide information on ash content (or mineral matter) which would intuitively have a strong influence on swelling behavior as it significantly affects the amount of gas which can be sorbed on a sample.
Objectives of our work were to assemble experimental apparatus, develop experimental procedures, and then measure coal matrix shrinkage coefficients at reservoir conditions.
Reservoir temperatures and pressures commonly encountered during coalbed methane recovery are not extreme conditions for strain gages. Many commercial gages would probably be quite adequate for this experiment.