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...SPE 103271 Analytical Solution for Injection-Falloff-Production Test Shi Chen, SPE, U. of Tulsa and Gaoming Li, SPE, U. of Tulsa and A. C. Reynolds, SPE, U. of Tulsa ... to publication review by Editorial Committees of the Society of Petroleum Engineers. by a falloff test, the major exception being the work of Electronic reproduction, distribution, or storage of any pa...cent papers 6,7,8 which used the Thompson-Reynolds steady-state theory 9,10 to A novel well-test for in situ estimation of relative permeabilities generate approximate analytical solutions for com...
...tional bubble point pressure, the water saturation distribution is procedure. For our special case, production starting with governed by the following partial differential equation: a nonuniform saturation dist...evolution of the saturation profile during is homogeneous), θ is a unit conversion factor, h is the production. After the saturation distribution is generated, reservoir thickness, q inj is the total water ...ating vertical well. After flow curve is the solid curve and the curve with circles this, a falloff test is run and then the well is put on is its derivative curve. As is well known 20 , the dashed ...
...e steps and the change in the shock locations over three time to better Saturation Evolution During Production. The fluid visualize our solution procedure and the change in the saturation flow during ...production follows the same governing equation distribution during ...production. We assume that (Eq. 1) for the water injection. However, the initial the speed of front is constan...
Abstract A novel well-test for in situ estimation of relative permeabilities was recently proposed. This test consists of three periods,injection of water into an oil reservoir, a falloff test and a producing period. The producing period is critical as it yields production data that reflects changes in sandface mobility and is thus highly sensitive to the parameters used to model relative permeability curves. A major shortcoming of the data analysis procedure proposed in previous work was that it required a numerical reservoir simulator for matching pressure data. In this work, based on Buckley-Leverett theory and ideas from a front tracking method, we derive an approximate analytical solution for the pressure response during an injection/falloff/production test (IFPT) by applying on the Thompson-Reynolds steady-state theory. By matching data to the analytical solution by minimization of a weighted least squares objective function, we generate estimates of absolute permeability, relative permeabilities and the well skin factor. We show the method can be applied with either power law models or B-splines. Introduction Beginning at least as early as 1952 (Verigin), various analytical or approximate analytical solutions for the pressure response during injection and/or falloff tests have been presented in the literature. In general, these solutions require a model for generating the saturation distribution as a function of time (piston displacement of Buckley-Leverett) during injection and assume that the front does not move during falloff so that the falloff solution is equivalent to solving a multicomposite single-phase reservoir problem where the pressure at the end of the injection solution period provides the initial condition for the falloff problem. Abbaszadeh and Kamal show that the pressure solution at the end of injection can itself be obtained from an equivalent multicomposite problem, whereas, Bratvold and Horne assume the validity of the Boltzman transform to generate the injection solution. Most solutions available consider only injection at a constant rate followed by a falloff test, the major exception being the work of Levitan who was able to generate a solution for multirate tests. Most solutions, including all those mentioned above, consider only one-dimensional radial flow problems, the major exceptions being Thambynayagam who presented injection/falloff solutions for a vertical restricted-entry well assuming piston displacement recent papers which used the Thompson-Reynolds steady-state theory to generate approximate analytical solutions for complete penetration and restricted-entry vertical wells as well as for horizontal wells. Peres and Reynolds showed that incorporation of the skin factor using the infinitesimally thin skin is invalid during the injection period; for example, for one-dimensional radial flow problems, they showed that a skin zone with a width of a few inches can have a pronounced effect on the injection pressure and its derivative for several hours. For a damaged well and an unfavorable mobility ratio, they showed that the injection pressure derivative may be negative for a considerable period of time. Because of this result, we use a finite-radius skin zone for the injection/falloff/production test (IFPT) considered here.
Kooijman, A.P. (Koninklijke/Shell E and P Laboratorium) | Halleck, P.M. (Terra Tek Inc.) | de Bree, Philippus (Koninklijke/Shell E and P Laboratorium) | Veeken, C.A.M. (Koninklijke/Shell E and P Laboratorium) | Kenter, C.J. (Koninklijke/Shell E and P Laboratorium)
...Society of Petroleum Engineers SPE 24798 Large-Scale Laboratory Sand Production Test A.P. Kooijman, KoninklijkeIShell E&P Laboratorium; P.M. Halleck,* Terra Tek Inc.; and Philippus de...ptual, analytical and numerical models forThis paper describes the results and interpretation sand production prediction have been developed,of a large-scale laboratory sand ...production test. In see e.g. [2-101, the value of these models may still the experiment, a real well with multiple...
...2 LARGE-SCALE LABORTORY SAND PRODUCTION TEST SPE 24798 between small-scale laboratory tests and field between the horizontal and vertical press...ure was observations by carrying out a large-scale sand kept at a prescribed value, which could be production test on an artificial well in the laboratory controlled by manually following an XY plot of the under r...ealistic, controlled conditions. required stress ratio. During the test flow rate, rock stresses and pore pressures were monitored ...
...ened and cement was poured into the wellbore. The cement composition deviated slightly from what is PRODUCTION FROM THE LABORATORY WELL used in the field. Some additives had to be omitted, because they would op...erate as retarders at the Test development relatively low temperatures in the laboratory. The intended ...test program is summarized in The 3" (7.63 cm) aluminum casing was pushed into Table 3. The main object...
This paper describes the results and interpretation of a large-scale laboratory sand production test. In the experiment, a real well with multiple perforations was simulated, using an outcrop rock selected to represent core material from a specific field. The objective of the experiment, which was the first of its kind, was to investigate the influence of both effective stress increase and drawdown on sand production behavior, taking into account the influence of the presence of casing and cement and of perforating. An additional objective of the test was to investigate the influence of a water cut on the sand produced. The laboratory well behaved very realistically, in terms of both oil and sand production.
Reliable predictions of sand production potential are required to make realistic sand production management and contingency planning possible. Unnecessary application of sand exclusion measures results in increased completion costs and considerable loss of well productivities. Further, sand prediction may assist in selecting the most attractive sand control techniques .
Although, over the years, a large number of conceptual, analytical and numerical models for sand production prediction have been developed, see e.g. [2-10], the value of these models may still be questioned, considering the discrepancy observed between the model predictions and field observations. To improve and validate the sand prediction models, reliable sand production data are indispensable. The sand production data available can be divided into laboratory sand production test data and field sand production data collected from real wells. Laboratory sand production tests typically concern small-scale simulation of flow through perforations or cylindrical cavities in stressed cylindrical samples (see e.g.). Advantages of such laboratory tests include the controlled stress and pressure boundary conditions, the extensive monitoring facilities available and the simple geometry used, which facilitates interpretation of the experiments. Field observations involve far more complex situations (e.g. perforation interaction), with many uncertainties concerning the actual downhole situation and only limited possibilities of imposing prescribed boundary conditions. Nevertheless, interpreting and predicting such field observations are the prime objective of sand prediction modeling.
...SPE 16555/1 TROLL HIGH RATE PRODUCTION TEST, PLANNING AND EXECUTION B. H. Nilssen Norsk Hydro Copyrtght 1987, Society of Petroleum EnglnHra T...on elsewhere is usually granted upon request provided proper credit is made. SUMMARY The high rate production test performed by Norsk Hydro on the Troll East structure during the summer of 1985 with the semi submer... number of specially designed, modified or adapted equipment items were used in order to fulfil the test objectives and maintain safe operations. These were: Jetting tool for casing cleaning. Gravel pack ...
...SPE 16555/2 TROLL HIGH RATE PRODUCTION TEST, PLANNING AND EXECUTION r L Objective No. 1 differed mainly from a conventional well ...test in that "high rate" meant a rate of up to 4.25 x 106 sM3/D (150 mm scf/D). The highest gas ...test rate previously obtained by Norsk Hydro on the Troll East structure using conventional drill stem ...
...the well could then be observe·d from one place· and immediate action taken when required. THE MAIN TEST STRING AND SURFACE EQUIPMENT A great effort was made to design a functional high capacity ...test string for the main ...test. Conventional equipment was modified and new equipment constructed where required to provide an ade...
This paper was prepared lor presentatiOn at OHshore Europe 87. The abstract should contain conspicuous acknowledgement of where and by whom the paper was presented. Publication elsewhere is usually granted upon request provided proper credit is made. SUMMARY The high rate production test performed by Norsk Hydro on the Troll East structure during the summer of 1985 with the semi submersible drilling rig Treasure Seeker required that a large number of specially designed, modified or adapted equipment items were used in order to fulfil the test objectives and maintain safe operations. These were: Jetting tool for casing cleaning. Gravel pack floor manifold to ease operations.
...78-1-880653-92-0; ISSN 1946-0066 Monitoring System for Seafloor Deformation during Methane Hydrate Production Test Tatsuya Yokoyama, Mio Shimoyama, Shinji Matsuda, Koichi Tago and Junya Takeshima OYO Corporation ...expected to be applied to the 1st MHWe have developed a monitoring system for seafloor deformation production test scheduled in the end of FY2012. The ...production testduring Methane Hydrate ...
...ystem first for evaluation 30 and its practical resolution is approximately 0.05 . The sensor has test, then complete a final model for actual operation as described in almost no temperature drift sinc...
...r two weeks Fig. 5 Flow chart of data processing in acoustic communication system In Shallow Water Test All eight monitoring devices completed were installed in the shallow sea floor of about 30 m depth,...about for one weeks hour on the sea floor, and raised up on the sea surface. It took three days to test all devices. The work procedure of shallow water ...test is shown in PERFORMANCE TESTS IN OFFSHORE Figure 6. As a result, all monitoring devices were conf...
We have developed a monitoring system for seafloor deformation during Methane Hydrate production test. Seafloor deformation is monitored by measuring subsidence and inclination of the seafloor. Subsidence is measured with change of water pressure on the seafloor. An inclinometer we selected is applied liquid electrolyte. According to simulation of seafloor deformation around the production hole, the range of subsidence will be from 0.1 m to 0.3 cm. This system has been installed and monitored on the seafloor at East Nankai trough during the production test of Methane Hydrate. We will continue the measurement by September 2013.
Sakurai, Shunsuke (Japan Oil, Gas and Metals National Corporation) | Nakatsuka, Yoshihiro (Japan Oil, Gas and Metals National Corporation) | Edwards, Terry J (Oilfield Production Technologies) | Hoskin, Ben John (Oilfield Production Technologies) | Manning, David Keith (Oilfield Production Technologies)
For the world's first offshore methane hydrate production test carried out in the Eastern Nankai Trough, depressurization method was used for the dissociation of methane hydrates in sediments. In that occasion, flow assurance and prevention of hydrate re-association in the wellbore was an important issue because methane-solving water under hydro-static pressure should be transported through the well, and cooled-down by seawater.
The condition is thought to be water dominant flow with small amount of free gas due to incomplete downhole gas separation, and there is possibility of flow blockage due to gas hydrate formation and accumulation, but knowledge about behavior of hydrates under such condition was not well known.
To investigate the potential for hydrate re-formation in the downstream of downhole separator including subsea pipes and equipment, Japan Oil, Gas and Metals National Corporation (JOGMEC) and Oilfield Production Technologies (OPT) developed a unique flow loop maintained at Nankai seabed temperature and pressure. The flow loop was some 18 m in length. Notably, 12 m of the flow loop was constructed in optically clear cast acrylic, which allowed image capture in horizontal and vertical flow lines, and at flow stagnation points, of
1. methane/water flows outside the hydrate region
2. the formation, development and flow characteristics of hydrate slurries
3. hydrate dissociation on de-pressurization.
In this paper we describe the flow loop design, and measurements of flow, temperature, pressure, and so on in a water dominant system. We also show captivating video taken by our high speed camera. The result was used for the design of the test plan and production system.
Zhou, Mingliang (University of Cambridge) | Ermao, Xu (University of Cambridge) | Soga, Kenichi (University of Cambridge) | Uchida, Shun (Technion- Israel Institute of Technology) | Yamamoto, Koji (Japan Oil, Gas & Metals Natl. Corp.)
Description of the proposed paper:
The fully coupled methane hydrate model developed in Cambridge was adopted in this numerical study on gas production trial at the Eastern Nankai Trough, Japan 2013. Based on the latest experimental data of hydrate soil core samples, the clay parameters at Eastern Nankai site were successfully calibrated. With updated clay parameters and site geometry, a 50 days gas production trail was numerically simulated using the code described in Klar et al. (2012). The geomechanical behaviour of hydrate bearing sediments under 3 different depressurization strategies were explored and discussed. To validate the fully coupled model, production history matching results between our model and JOE’s simulation were compared. Parameter sensitivity of gas production is also investigated.
The geomachanical aspects of hydrate-bearing sediments during the gas production is still under study. In geotechnical perspective, there are several potential geohazards can be caused by gas production: Wellbore instability, Damages in well casing or supporting well infrastructure, Submarine landslide, Seafloor instability and Seafloor subsidence.
In order to investigate these geohazards, a cost effective method is to have numerical simulation of the gas hydrate production. Therefore, accurate numerical modeling of the geomechanical behavior of the hydrate-bearing sediments is required.
Results, Observations, and Conclusions:
The figure illustrates the two model geometries considered in this simulation: the axisymmetric case (left) and the plane-strain case (right). Both geometries were simulated to simplify the real site three-dimensional problem to 2D models.
The simulation results from axi-symmetrical and plane-strain models suggest the slope of the seabed only affects mechanical properties while no significant impact on the dissociation, temperature and pore pressure. After PT recovery, large settlements above the perforation zone and small uplift underneath the production zone are observed.
The history matching comparison suggests good agreement between our model and JOE’s results on gas and water production during gas production trial. Parameter sensitivity analysis concludes the sea water salinity is a dominant factor for gas production.
Significance of Subject Matter:
This numerical study provided important advisory information for the scheduled first offshore gas production trial at the Eastern Nankai Trough, Japan 2013.
The world’s first offshore gas production test from methane hydrate deposits was conducted in March 2013, at the test site located on the margin of Daini Atsumi Knoll, off the coasts of Atsumi and Shima peninsulas, in the easten Nankai Trough, of Japan. Approximately 120,000 cubic meters of methane gas was produced in 6 days using the depressurization technique.
The test was a significant advance in Japan’s national program to construct the technical base for future commertial methane hydrate resource development. A series of researches for more than 10 years, including two times of onshore production tests in Mallik field and explorations in eastern Nankai Trough, were required to reach the test.
This report reviews Japan’s research history for methane hydrates.
...SPE-172515-MS Keeping up With Technological Advances - An Innovative Approach to Validate Production Test Data M.N. Khan, and T. Felix Menchaca, Abu Dhabi Marine Operating Company Copyright 2015, Society... reservoir performance data than in the past. Multi-Phase Flow Metering is an expedient addition in production testing domain. As per the recent statistics, globally, approximately 4000 Multi-Phase Flow Meters ...shing and implementing the appropriate data validation workflows on the MPFM data. The conventional production test data validation approach can be applied to the MPFM measurements up to a certain extent, but in ord...
...ct viability analysis y Geologist for the validation of geological conceptual model In the past the production data acquisition could only be carried out with the help of the ...test separator where monophasic flow rate measurements are taken at separator's liquid and gas outlets. ...Depending upon the fluid type and the test objectives, a number of additional equipment is usually required to carry out the ...
...515-MS 3 Figure 1--Conventional Surface Well Testing Setup (Expro Website) Measurement Philosophy Test separator is a flow rate measurement device which is equipped with a series of mechanical barriers ...
Abstract The technological advances in oil and gas industry are enabling the operating companies to monitor their hydrocarbon reservoirs closely. Today reservoir surveillance engineers are able to acquire more well/reservoir performance data than in the past. Multi-Phase Flow Metering is an expedient addition in production testing domain. As per the recent statistics, globally, approximately 4000 Multi-Phase Flow Meters (MPFM) installations are providing reliable measurements under different applications. As with any new technology the philosophy behind MPFM measurements is blurry for many users, who find difficulty establishing and implementing the appropriate data validation workflows on the MPFM data. The conventional production test data validation approach can be applied to the MPFM measurements up to a certain extent, but in order to find the source of discrepancies in MPFM data, additional processes are required to be included in the workflow. The production history of the majority of hydrocarbon reservoirs in the world was built on conventional test separator flow rate data. Introducing a new measurement technology with different set of accuracies and different working principles has been a challenge for the production data users. To standardize the data validation process, a systematic approach can be implemented to validate the production testing data from different sources, which not only will help the end users to gain confidence in MPFM flow measurements but also will assist identifying the sources of discrepancy in MPFM measurements during day to day operations. This paper will explain the stepwise data validation approach that can benefit different production test data users in oil and gas industry.
Bruni, Thomas (ENI E&P Division) | Lentini, Amelia (ENI E&P Division) | Ventura, Stefano (ENI E&P Division) | Gheller, Ruggero (ENI E&P Division) | Maybee, Charles A. (Landmark Graphics Corporation) | Pinedo, Jorge E. (Landmark Graphics Corporation)
...SPE 84881 A Technically Rigorous and Fully Automated System for Performance Monitoring and Production Test Validation Thomas Bruni, SPE, ENI E&P Division, Amelia Lentini, ENI E&P Division, Stefano Ventura,...tation at the SPE International Improved Oil Recovery providing a more reliable and time effective production test Conference in Asia Pacific held in Kuala Lumpur, Malaysia, 20-21 October 2003. validation process...position of the Society of Petroleum Engineers, its officers, or members. Papers presented at from production tests, dependable ...
... Workflows strings and calculations to perform. Rigorous system analysis The major problem that the production engineers were models for each producing string were constructed and facing with the old system was...h as locating, exporting and reformatting of data consumed daily performance monitoring and one for production valuable engineering time from beneficial activities like ...test validation. analysis and diagnosis of well performance. Engineering Daily performance surveillance:...
...SPE 84881 3 analysis model and should be reflective of the last valid Field Examples production test. The system was deployed to ...production/gathering centers: 1. Gas Plant Network. It comprises seven offshore gas ...Production test validation: Utilizing the string fields, 14 platforms and about 180 ...
Abstract This paper describes the integration between a dynamic surveillance tool and a system analysis tool to provide the surveillance engineer with a new, fully automated and technically rigorous system, capable of true performance monitoring and reliable production test validation. The combination of the software tools and workflows resulted in an innovative Production Management and Optimization system (PROMO), with new and extended capabilities beyond those of either of the stand-alone packages. Algorithms were defined in order to automatically compare actual and modeled production (taking into account FTHP variations) on a daily basis. Additionally, as new production test data becomes available, the system can automatically display it on a calibrated IPR plot for fast and rigorous validation. The system has also been designed such that when a new well test is approved and validated, the IPR curve will be automatically re-calibrated to honor the new performance measurements. In principle no gas or oil field is outside the scope of such an application. Once an appropriate interface is set up to allow for data exchange between the surveillance and system analysis tools, it is a matter of building the appropriate processes that will yield the most beneficial results in terms of production optimization and data validation. The addition of data linkages to corporate data warehouses results in a system that requires little maintenance of input parameters and is always up-to-date with respect to the available data. The PROMO system, currently deployed in one gas plant (comprising of seven offshore gas fields, 14 platforms and 180 production strings) and one oil plant (comprising of two onshore oil fields and 10 production strings), is allowing the production engineers to easily identify under-performing strings (completions) and promptly intervene. In addition to providing a more reliable and time effective production test validation process, the engineer can fully analyze current well performance with daily, historical and forecasted data. Additional benefits include calculation of historic SBHP's from production tests, dependable production allocation (with great benefit for overall field management and reservoir modeling) and considerable time savings as pertinent data is automatically (as opposed to manually) handled and used in the system analysis algorithms. Introduction Production surveillance and reliable allocation play a major role in the efforts to optimize and maximize production from a field. Many software solutions exist to monitor actual performance variables of well and field systems. Just as important is performance modeling through system analysis methods and again the relevant commercial packages are several and well established. However, the added value from combining the two systems (production monitoring and system analysis) has not been entirely captured to date - at least not to its full potential. The operator involved in this project was no exception. Production data was stored in two corporate databases (daily and monthly production) and monitored using desktop spreadsheets. The inherent drawbacks to this surveillance process were redundant, static and localized subsets of corporate databases, no standardized or transferable workflows or formats, lack of strict data quality control and integrity, and poor fit-for-purpose of the spreadsheet software. Additionally the overall system was lacking the integrated system analysis capabilities to effectively monitor string/well performance. The necessary system analysis workflows were being achieved using an industry standard software tool, but at the expense of manual data entry. An obvious problem with such a disjointed system was the lack of communication between the two tool sets, resulting in lengthy production data handling and formatting before data could be returned to the system analysis software for the computations. Also there was no mechanism in place to return the system analysis results for use in the surveillance process.
...Long-Term Gas-Hydrate-Production Test, North Slope, Alaska To investigate the technical feasibility of gas ...production from hydrate deposits, a long-term field ...test (lasting 18 to 24 months) is under consideration in a project led by the US Department of Energy. A...
...6 10 6 Horizontal Well S H 0.75 14 10 3 Release (Q R ) Production (Q P ) 5 12 Horizontal Well V R 10 4 V P V F 8 3 6 Vertical Well 2 Release (Q R ) Verti...cal Well Production (Q P ) V R 4 V P V F 1 2 S H 0.75 0 0 0 100 200 300 400 500 600 700 7000 100 200 300 400 50...F : horizontal wells vs. a single single vertical well during the proposed long-term vertical well. production test. S H hydrate saturation. portion of the unit has two GH-bearing Horizontal-Well ...
...Safety / free gas, V F , was very low in the reservoir incidence of incoming seismic waves, during production, which exhibits a consistent and their use can infer changes in elastic Security / Environment / ...but very mild upward trend during parameters and densities across a the 2-year test period. The low levels rock/hydrate or hydrate/gas interface. If Social Responsibility of V F , a...was produced. changes in the seismic signature of the hydrate layer around the well. Vertical-Well Production It is possible that the dissociation Fig. 2 shows the evolution of Q R and Q P of gas from hydrate...
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22152, "Evaluation of the Hydrate Deposit at the PBU-L106 Site, North Slope, Alaska, for a Long-Term Test of Gas Production," by George J. Moridis, SPE, and Matthew T. Reagan, SPE, Lawrence Berkeley National Laboratory; Heidi Anderson-Kuzma, SPE, East Donner Research; Yang Zhao, University of California at Berkeley; Katie Boyle, Lawrence Berkeley National Laboratory; and James W. Rector, University of California at Berkeley, prepared for the 2011 Arctic Technology Conference, Houston, 7-9 February. The paper has not been peer reviewed.
To investigate the technical feasibility of gas production from hydrate deposits, a long-term field test (lasting 18 to 24 months) is under consideration in a project led by the US Department of Energy. A candidate deposit involving the C-Unit in the vicinity of the PBU-L106 site on the North Slope, Alaska, was evaluated. The results indicate that production from horizontal wells may be orders of magnitude larger than that from vertical wells.
Gas hydrates (GHs) are solid crystalline compounds of water and gaseous sub-stances that are described by the general chemical formula G⋅NH H2O. In the GH clathrates, the molecules of gas, G (referred to as guests), occupy voids within the lattices of ice-like crystal structures. If gas and H2O availability is not a limitation, hydrate deposits can occur in two distinctly different geographic settings in which the necessary conditions of low temperature, T, and high pressure, P, exist for their formation and stability: in the Arctic (typically in association with permafrost) and in deep ocean sediments. CH4 is the dominant GH-forming hydrocarbon gas in natural hydrates that occur in geologic media. Under standard T and P (STP) conditions, each cubic meter of simple CH4 hydrate releases, upon dissociation, approximately 164 m3 of methane and 0.8 m3 of H2O.Classification. Natural GH accumulations are divided into three main classes on the basis of simple geologic features and initial reservoir conditions. Class-1 settings have two layers: a hydrate- bearing layer (HBL) and an underlying two-phase-fluid zone containing mobile gas and liquid water. A distinct feature of Class-1 settings is that the base of the GH-stability zone coincides with the bottom of the HBL. Class 1 is the most desirable target because it is the easiest to destabilize to release gas. In Class-2 settings, an HBL overlies a zone of mobile water. Class-3 accumulations have a single HBL with no underlying zone of mobile fluids.