ADCO ESP Pilot

During the drilling of horizontal shale oil wells in the Cangdong Sag, the low ROP (Rate of Penetration), high safety risk, and uncertain cementing quality impeded the efficient exploration and development of shale oil. To address these problems, investigations were implemented on the detailed prediction of formation leakage pressure and collapse pressure. They were then carried out the optimization of casing programs and borehole trajectories and the personalized design of PDC bits. Further, the matching technologies such as brine drilling fluid, rotary steering drilling, ductile cement slurry, and floating displacement cementing were integrated, forming an optimized and fast drilling technology for the horizontal shale oil wells in the Cangdong Sag. This technology was applied in 20 horizontal shale oil wells in the Cangdong Sag, and the cementing quality was improved by 30.4%. For the wells with a depth of more than 4 500.00 m, the average ROP increased by 20.2%, and the average drilling cycle was shortened by 30.6%. For wells with a depth of lower than 4 500.00 m, the average ROP increased by 82.9%, and the average drilling cycle was shortened by 49.9%. These results demonstrated that the proposed technology could meet the requirement for the optimized and fast drilling of horizontal shale oil wells in the Cangdong Sag, providing a technical means for the efficient exploration and development of horizontal shale oil wells and also a reference for the drilling technology optimization of unconventional oil and gas reservoirs in the oilfields of China.

To carry out remedial work in oil wells through the production tubing string, a method using a continuous length of steel coiled tubing is used. In horizontal wells substantial friction forces are generated which resist the motion of the tubing as it is pushed into the well. As the penetration increases, the friction forces arising from the contact of the tubing with the inner casing wall increase too, and the tubing buckles. The buckling is initially sinusoidal but eventually transforms into helical. At this point the force required to push the tubing rises dramatically, and the maximum penetration is then rapidly reached. Considerable economic benefits could be gained if the limits on the maximum penetration of coiled tubing in horizontal oil wells could be increased. This article discusses ways of increasing the penetration of coiled tubing in horizontal oil wells by managing the geometry of the coiled tubing. It is shown that the best strategy is to keep the external diameter of the coiled tubing constant, and to make up the coiled tubing from several sections, each with uniform, but increased wall thickness. It is shown that with two sections the maximum penetration can be increased by about half, and that with three sections the maximum penetration can be increased by about two-thirds.

Corrosion problems of deep well tubings and their control measures are discussed. As one of the economical solutions, metal-lined tubings are proposed. It is shown that the metal liner can be tightly fitted by the newly developed thermo-hydraulic fit method. The selection of corrosion-resistant material for the liner is discussed. Some designs of the tubing joint and their manufacturing methods pre proposed. Introduction With the seriousness of an energy shortage, the drillings of oil and gas wells have become more active. In the last few years, the number of drilled wells has increased rapidly as shown in Fig. 1. It should be noted that eighty percent of these wells were drilled in the United States. Fig. 2 shows the depth distribution of oil and gas wells drilled in the United States in 1977. It can be seen that the numbers of oil and gas wells are about the same, but, in general, there are more gas wells at deeper depths than oil wells. As shown in Fig. 3, well depth increases each year, and recently an exploratory well deeper than 10,000 m has been drilled. As the well depth increases, the down hole pressure and temperature rise. For instance, in some severe wells at a depth of 6,000 m, the pressure and temperature are more than 1,000 bar and 200°C respec. tively. Therefore, the strength of the tubings used in such severe conditions is a very important factor for deep wells because they have to sustain their ownweight also. Figure 4 diagrammatically illustrates the transitions of design conditions with the increaseof well depth. Figure 5 shows the relationship between well depth and axial and hoop stresses of API standard tubings with various pipe 'dimensions. It isknown roughly that the strength of class P-I05 is required for the tubing of a 6,000 m well. Another substantial problem in deep oil and gas wells is corrosion. This is mainly due to H2S and C02 which are contained in crude oil and natural gas The density of these contaminants is increased with well depth, and, together with high pressure and high temperature, the corrosion reaction is accelerated. To solve all the above problems in deep wells, a new type of economical, high strength tUbing which has high corrosion resistance is expected. At present a super Ni alloy tubing, which is extremely expensive, tends to be used. As a solution, the authors propose the Tight Fit Tubing (hereinafter referred to as TFT) which is lined inside with corrosion-resistant alloy to meet the above three requirements for the tubing of deep wells. The thermo-hydraulic fit method used here for TFT has been developed to produce the corrosionresistant pipe, TFP, for corrosive flow lines as reported in Ref. 1.

A recent study by the Wall Street Journal reveals that the hydrofractured horizontal wells in shales have been producing less than the industrial forecasts with the empirical hyperbolic decline curve analysis (DCA). As an alternative to DCA, we introduce a simple, fast and accurate method of estimating ultimate recovery in oil shales. We adopt a physics-based scaling approach to analyze oil rates and ultimate recovery from 14,888 active horizontal oil wells in the Bakken shale. To predict the Estimated Ultimate Recovery (EUR), we collapse production records from individual horizontal shale oil wells onto two segments of a master curve: (1) We find that cumulative oil production from 4845 wells is still growing linearly with the square root of time; and (2) 6401 wells are already in exponential decline after approximately seven years on production. In addition, 2363 wells have discontinuous production records, because of refracturing or changes in downhole flowing pressure, and are matched with a linear combination of scaling curves superposed in time. The remaining 1279 new wells with less than 12 months on production have too few production records to allow for robust matches. These wells are scaled with the slopes of other comparable wells in the square-root-of-time flow regime. In the end, we predict that total ultimate recovery from all existing horizontal wells in Bakken will be some 4.5 billion barrels of oil. We also find that wells completed in the Middle Bakken formation, in general, produce more oil than those completed in the Upper Three Forks formation. The newly completed longer wells with larger hydrofractures have higher initial production rates, but they decline faster and have EURs similar to the cheaper old wells. There is little correlation among EUR, lateral length, and the number and size of hydrofractures. Therefore, technology may not help much in boosting production of new wells completed in the poor immature areas along the edges of the Williston Basin. Operators and policymakers may use our findings to optimize the possible futures of the Bakken shale and other plays. More importantly, the petroleum industry may adopt our physics-based method as an alternative to the overly optimistic hyperbolic DCA that yields an ‘illusory picture’ of shale oil resources.

A comprehensive analysis on the longitudinal fracture in the tool joints of drill pipes

As development of deep oil reservoir, more and more deep and ultra-deep wells, of which the chief lifting method is sucker-rod pumping system, are drilled. There often exist problems for systems above such as high load and low pumping efficiency. Because of low density and high intensity of carbon fiber rod, polished rod load can be decreased by using carbon fiber rod to increase safety factor. Meanwhile, since elastic modulus of carbon fiber rod is low, stroke loss will be increased by unreasonable lifting parameters. Test of carbon fiber rod was conducted in Xinjiang oil field in order to verify the feasibility of carbon fiber rod in deep oil wells and evaluate load shedding and energy saving effect. To lighten field test workload, a 3D rod mechanical model was built to simulate conditions of different production parameters. From the results of field test and simulation, it is indicated that carbon fiber rod owns better load shedding capacity and higher strength intensity; under the condition of deep wells, more stroke loss may be caused by carbon fiber composite rod. For some conditions, pumping efficiency is low, even worse, rod lock problems like gaslock may appear; reasonable combination of rod string and production parameters can improve the feasibility of carbon fiber rod.

Traditional gas-lift technology blossomed between 1929 and 1945, with about 25000 patents being issued during this time (Wikipedia 2017). Minimal innovation other than improved materials has been realized since then, with gas-lift in the 1000 psig injection pressure range being the norm onshore. The case for high pressure gas-lift to eliminate the need for problematic gas-lift valves is made, as technology and conditions exist to implement it now, as has been done offshore. The concept of High Pressure Gas-lift (herein after referred to as HPGL), as discussed in SPE 14347 (Dickens 1988), has two potential onshore applications. First, total elimination of gas-lift valves in horizontal wells with sub-7000 psi BHP's. This is feasible due to improvements in compressor technology created to support CNG fuel, and elevated casing pressure ratings necessitated by hydraulic fracturing requirements. A second application is replacing failure-prone submersible lift as the initial form of artificial lift in horizontal oil wells by reversing flow with high rate, high pressure gas-lift. The case for eliminating failure-prone gas-lift valves is self-evident. However, the case for the second application will be proffered. Conventional gas-lift, while recognized as excellent for producing high volumes of solids- laden fluid from deviated wells, underperforms ESP's in new horizontal oil wells due to frictional losses associated with high tubing flowrates. The case will be made that SPGL combined with reverse flow mitigates the frictional losses associated with high flowrates. Similar to a coil tubing cleanout using high pressure nitrogen, high pressure natural gas can lift large volumes of fluid without the need for gas-lift valves. Technology and products for HPGL currently exist. Multiple compressor designs will be summarized to show that only one additional stage of compression is needed to support HPGL, with three and four stage designs being capable of performing the task. The recommendation will be made that HPGL compressors be assembled from readily available components, and that multiple pilot tests be made by industry. The importance of maintaining temperatures through the compression process high enough to prevent hydrocarbon condensation will also be explained.

Dealing with mature offshore oilfield has complicated problems both surface and subsurface. In the reservoir condition high water cut wells make some bad impact in the production stages. Liquid handling facilities, tubing pipeline erosion, broken sand control, and high power consumption are several problem caused by high water cut wells. WW is an offshore oil field which has developed since 1990s with OOIP 758 MMBO. This reservoir was divided into several layer, 33 series is depleted reservoir with water injection since year 2000s (RF 23%) and 35 Series has strong water drive as its driving mechanism (RF 56%). Almost 85% of the oil wells is producing with water cut more than 97%. Increasing water cut or even watered out phenomenon was frequently happen during production stage, some of this problem was happen after well intervention such as after pump replacement. This paper will show the successful case of decreasing water cut significantly from WW D-29, WW H-12, II A-22. Laboratory test was firstly done to check the compatibility test of the rock with modified completion fluid. This chemical was mainly works as phase change water control and oil stabilize well for completion fluid. It was pumped simultaneously with regular completion fluid (filtered drill water and additives). Killing well was mandatory procedure when shut in wells will be repaired. GGR team supported by Production and Workover Team did integrated study to choose the chemical and well selection based on some criteria. WW D-29, WW H-12, and II A-22 are wells which have implemented modified completion fluid treatment. Those wells are produced from sandstone reservoir and drilled more than 10 years ago. During production period, water cut was significantly jumped due to several reason, such as pump replacement job, re-start up after the well trip off, etc. The result of the project were very excellent, WW D-29 (from 98% to 86%, gain +/− 180 bopd), WW H-12 (from 80% to 40%, gain +/− 250 bopd) and II A-22 (96% to 75%, gain +/− 130 bopd). These result give a lot of impact of increasing oil production in WW Field. This paper will elaborate how to solve the problem in offshore mature oil field special case for high water cut wells using modification of completion fluid treatment. We have succeeded increasing oil reserves.

Background/Objectives: The objective of this study is to develop a new compact hydraulic positive displacement motor that would operate without rotor vibrations. Methods: Assisted by 3D printers, the models of the new hydraulic machines have been developed. The results of the laboratory and bench testing confirmed the relevance of the selected area of investigations. Findings: The results of the calculations and the laboratory tests of the models of the hydraulic machines showed that upon introducing some constructive adjustments such class of machines can be used for developing new compact hydraulic positive displacement motors that would operate with no rotor vibrations in the process of drilling oil wells. The major objective of the undertaken investigations is to create the new and more efficient sealing that is supposed to be installed between the cylindrical rotor and cylindrical stator in the hydraulic machine. The novelty of the structure rests with the application of a partitioning seal where separate sections of the seal are installed consecutively along the screw line. Thereat, the design of the new machine avoids using any screw surfaces and applies only flat or cylindrical surfaces. The results of the undertaken scientific and design activities can also be used for developing hydraulic machines in other industries that set strict regulations on the vibration levels, on the weight and dimensions of the process equipment. Applications/Improvements: Principal area of applying the new design is related to drilling downward and horizontal oil and gas wells. Compact motor can be used for the repairs at the oil wells.

The need to re-develop one of Shell's mature fields located in the offshore area of the Niger Delta of Nigeria was necessitated by it's drastically declining production performance over the years. The Bonny field which commenced production in 1973, had a peak production oil rate of 40 Mbpd in 1976. This however decreased over the years to its present rate of 5Mbpd. Unearthing the reason/reasons for this decline in production and developing a blue print for resuscitating production in this field is the main thrust of this paper. Introduction The acquisition of 3-D seismic data between 1994-1995 in this field having a total of 24 wells and its subsequent interpretation between 1996-1997 necessitated the commencement of an integrated petroleum engineering subsurface review, which was carried out between 1997-1999. Results of this review identified the root causes of the decline in production, and also showed significant increases in the field's hydrocarbon initially in place (HCIIP) volumes/ultimate recovery (UR). The large undeveloped reserves in the field triggered the subsequent Development Concept Selection (DCS) and Field Development Plan (FDP). A phased development strategy throughout the fields life cycle has been adopted to restore the field to it's optimum production level, enhance utilisation of facilities and maximise the value of additional data gathering exercise, thereby optimising profitability whilst minimising risk. To achieve this, a two-phase development strategy backed by an optimum economic option has been put in place. The phase one development strategy involves the drilling of 5 new horizontal oil wells and 4 new vertical/deviated gas wells all targeted at only 3 of the 25 hydrocarbon bearing reservoirs in the field. With this, it is estimated that about 95.5 MMstb (about 65%) out of 146.6 MMstb of undeveloped reserves in the field would be developed. The phase 1 development plan further integrates the development of 1388 Bscf of gas reserves in one of the 3 reservoirs. This takes place before 2010. The phase two development which is less significant will focus on drilling 13 horizontal wells and recompleting 5 existing wells targeted at 11 reservoirs. This will only take place after a comprehensive review of the phase 1 field development programme subsequently. Field Location and History The Bonny field is located in OML-11 (Figure 1) approximately 6km northeast of Bonny Crude Oil Terminal (BCOT), in the southern fringes of the Niger Delta, within the Eastern Swamp/offshore Asset Area of Shell Nigeria (SPDC). The field was discovered in 1959 by BONN-2 and to date, 24 wells have been drilled. Twenty-five hydrocarbon-bearing sands have been penetrated in the field between the depths of 5500 ftss and 11050 ftss. The first 4 wells (1958-1962) were used to explore and appraise the field before a development phase involving 16 wells was embarked upon between 1970 and 1974. Of the 24 wells drilled so far, 22 were completed as oil wells while the last 2 (BONN-23 and BONN-24) were completed as gas wells to provide fuel gas to the Bonny Crude Oil terminal (BCOT).

To carry out remedial work in oil wells through the production tubing string, a method using a continuous length of steel tubing or coiled tubing is used. Furthermore, coiled tubing can also be used for drilling and extending existing wells. In horizontal wells, substantial frictional forces are generated which resist the motion of the tubular drill pipe as it is pushed into the well. As the penetration increases, the frictional forces arising from the contact of the tubing with the inner casing wall increase too, and the tubular pipe buckles. The buckling is initially sinusoidal but eventually transforms into helical. At this point the force required to push the tubular drill pipe rises dramatically, and the maximum penetration is then rapidly reached. To date, scale model experimental studies on horizontal wells have not reproduced the actual conditions occurring in the wells. A new experimental rig has been designed that allows for the simulation and observation of all significant parameters. An analytical model has also been developed which is in excellent agreement with the experimental data. Governing modelling parameters have been identified which suggest ways to increase the penetration of tubular drill pipes in production oil wells.

Due to variables like wellbore deviation variation and flow rate, the local flow velocity in the output wellbore of horizontal shale oil wells varied significantly at various points in the wellbore cross-section, making it challenging to calculate the total single-layer production with accuracy. The oil–water two-phase flow rate calculation techniques for horizontal wells developed based on particular flow patterns and array spinners had excellent applicability in their respective niches but suffered from poor generalizability and demanding experience levels for logging interpreters. In this study, we employed five spinners in a triangular walled array instrument to create the multi-decision tree after figuring out how many leaf nodes there were and examining the defining characteristics of the observed values gathered under various experimental setups. The construction of the entire oil–water two-phase flow prediction model was made possible when the random forest regression approach was used with it. The total oil–water flow rate at each perforated layer was predicted using the model in sample wells, and the mean square error with the third party’s interpretation conclusion was 1.42, indicating that the model had an excellent application effect. The approach, which offered a new interpretation method for calculating the oil–water two-phase flow rate of horizontal wells based on multi-location local flow rate, required less interpretation knowledge from the interpreter and had a stronger generalization capacity.

As a result of current commodity price differentials, North American resource development has shifted towards unconventional liquids-rich and light tight oil plays. Due to the low permeability of these plays, extensive hydraulic fracturing is commonly required for commercial development. Operators are seeking new methods to characterize hydraulic fractures, particularly early in the well life. One such method is to utilize regularly gathered high frequency (hourly or greater) fluid production and flowing pressures to model the flowback process. Previous studies have suggested that this data can be quantitatively analyzed to estimate hydraulic fracture half-length and other fracture properties. Flowback of multi-fractured horizontal tight oil wells, stimulated with water-based fluids, commonly exhibit two distinct segments: a) a short period of single-phase water flow, which continues until breakthrough of formation fluids; and b) multi-phase flow (water, oil and gas) following breakthrough. The first flow regime observed in data collected at common frequencies typically consists of fracture storage/depletion of fracture fluid. This flow regime is followed by the breakthrough of hydrocarbon and formation water which results in a deviation from the depletion signature. The analysis procedure used for analyzing this data builds upon the analytical history-matching methodology presented by Clarkson and Williams-Kovacs (2013b). Consistent with the previous work we model the first segment as a single phase depletion of the fracture pore volume, from which a pre-breakthrough estimate of fracture permeability and half-length can be determined. The second segment is modelled by assuming transient linear flow of oil and formation water to the fracture, under the assumption of perfect displacement of frac water by formation fluids. From the second segment we are able to estimate long-term effective fracture permeability and half-length. However, as pointed out by Clarkson and Williams-Kovacs (2013b) there is a large degree of uncertainty in this type of analysis as a result of the number of unknowns which are being adjusted to provide an adequate history-match. To better understand the uncertainty and the impact of each parameter, stochastic simulation will be used to provide a range of parameter values, which provide an adequate fit of the data, and to determine which parameters have the greatest impact on the match. Additional improvements over the previous work include the consideration of different fracture geometries, the use of several fracture models to estimate fracture permeability, modeling produced water salinity to track the contribution of formation water and salt dissolution and additional constraints on relative permeability curve selection. The field case presented by Clarkson and Williams-Kovacs (2013b) for a prolific light tight oil reservoir is reanalyzed, along with a second well from the same pad for proof of concept and demonstration of the developed techniques.

Proppant scaling in the horizontal shale oil wells is a common problem in the Qingcheng Oilfield, one of the largest shale oil producers in China. However, few studies have focused on the mechanism of the proppant scaling during the flowback stage of hydraulic fracturing. To elucidate the scaling mechanism, in this study we collected the samples of produced water and solid scales and analyzed their compositions. The experimental simulations of the static and dynamic scaling processes using fracturing fluids, formation water, and reservoir rocks were also performed. In these experiments, the scale was found to be mainly SiO2 combined with FeCO3 and/or CaCO3. FeCO3 was dominant at the initial stage of the flowback, and CaCO3 became dominant at later stages of the flowback and during the stable production stage. It is believed that the high percentage of ferrous minerals (e.g., 46.4% of ferrocalcite) in multiple formation rocks is an essential reason that the proppant scaling happened during the flowback stage. The Fe2+ and Ca2+ ions were believed to be released via reservoir rock reacting with the fracturing fluid under the reservoir temperature and pressure (e.g. 60 °C, 20MPa). In addition, the FeCO3 formed in the initial flowback stage of the fracturing has the greatest impact on production.

Canada has played a prominent role in the development of horizontal drilling technology. To date, over 1,400 "grassroots" and "re-entry" wells have been drilled. Although other countries have experienced greater numbers of wells, the number of different types, varieties, and formations tested with this technology in Canada is unparalleled. Due in part to the exponential growth of horizontal well applications since the mid-1980's, coiled tubing CCT) technology in Canada has been adapted and evolved for more traditional uses such as horizontal well stimulation, evaluation, workovers, and clean-outs. The principal nontraditional aspect of CT is its use in drilling operations. This paper will deal with the current state and recent advances in CT horizontal drilling in Canada, A brief historical perspective will be presented that highlights Canada's presence as a pioneer in CT drilling and documents its evolution from vertical re-entries dating back to 1974, grassroots vertical wells in 1976, to the industry's current efforts at vertical and horizontal CTD. The principal Canadian service companies are reviewed in terms of present capabilities in CTO applications and the perceived driving forces that are stimulating the development of this emerging technology. The key factors such as diameter and fatigue life of the coil, length limitations, bottom hole assemblies, surveying methods and the economic and market factors affecting CTO relative to more conventional drilling techniques are reviewed. Finally, the future technological, market and economic developments necessary for the successful implementation of CTO for grassroots vertical and horizontal well re-entry projects are suggested. Introduction The exponential growth in the number of horizontal well applications in Canada and internationally over the past eight years has led to a relatively rapid development of both personnel and equipment to enhance the horizontal drilling method of exploiting existing oil and gas pools. In Canada, there are an estimated 70,000 producing wells: 40,000 gas wells and 30,000 oil wells. Recently, the National Energy Board (NEB) presented a study on horizontal oil wells and their impact on future crude oil supply in Canada. They estimated that there is a potential market of over 12,000 horizontal wells that can be economically drilled within 1,800 oil pools at a market price of $20 US/Bbl. Of these 12,000 wells, 5,000 were believed to be grassroots in nature (1 I 100 have been drilled to date) while 7,000 were horizontal re-entries through existing cased wells (300 have been drilled to date). Of the 6,700 remaining re-entries, the competition for services will be between slim hole (less than or equal to 6–1/4 in. hole size) conventional drilling systems using drilling rigs or modified service rigs and coiled tubing drilling (CTD) technology. Add to this potential market vertical deepenings, horizontal lengthenings and grassroots wells coupled with increasing interest in horizontal exploitation of gas pools, and the development of CTD appears to be poised for exponential growth in Canada over the next five years. Some of the questions that will be addressed during the course of this paper are: