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.

Abstract

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.

Introduction

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 [1].

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.[11]). 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.

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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.

ABSTRACT

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.

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.

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.

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.

Introduction

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.