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Search SPE International Improved Oil Recovery Conference in Asia Pacific: production test
A Technically Rigorous and Fully Automated System for Performance Monitoring and Production Test Validation
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.
- North America > United States > Texas > Coleman County (0.24)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
An Innovative Approach To Integrate Fracture, Well Test and Production Data into Reservoir Models
Bahar, Asnul (Kelkar and Associates, Inc.) | Ates, Harun (Kelkar and Associates, Inc.) | Al-Deeb, Maged H. (ADCO) | Salem, Salem E. (ADCO) | Badaam, Hussein (ADCO) | Linthorst, Steef (ADCO) | Kelkar, Mohan (The University of Tulsa)
...SPE 84876 An Innovative Approach To Integrate Fracture, Well Test and ...Production Data into Reservoir Models Asnul Bahar, SPE, and Harun Ates, SPE, Kelkar and Associates, Inc., Mag...s prepared for presentation at the SPE International Improved Oil Recovery simulation to integrate production data. The flow simulation at Conference in Asia Pacific held in Kuala Lumpur, Malaysia, 20-21 Octo...
...2 SPE 84876 based on core measurements alone cannot honor the well test coverage, which in turn will improve the statistics of results and need to be properly modified. t...een core-derived permeability with An important feature that needs to be satisfied is that the well-test derived permeability should be done carefully petrophysical properties have to be consistent with t...me volume as should be in agreement with the underlying facies/rock volume investigated by the well test. type description. 5 2. Measurment Scale: Due to the scale differences, i.e., fine In addition ...
...bility 500m, 750m, and 1000m, were generated for this study. The is in general lower than the well test names were based on the average fracture length used to permeability, when a mismatch between the t..., three maps are similar to each other, but in fact some EF, defined as the ratio between the well test kh and the differences exists in the detail. simulated kh, as shown in Eq. (1) below. The hydrauli...ater breakthrough analysis were also kh welltest EF (Eq. 1) performed. It was concluded that the production in the upper kh model part of the reservoir (Unit U1) was mainly enhanced by fracture. On the ot...
Abstract This paper presents an innovative approach to integrate fracture, well test and production data into the static description of a reservoir model as an input to the flow simulation. The approach has been successfully implemented into a field study of a giant naturally fractured carbonate reservoir in the Middle East. This study was part of a full field integrated reservoir characterization and flow simulation project. The main input available for this work includes matrix properties, fracture network, well test and production data. Stochastic models of matrix properties were generated using geostatistical methodology based on well logs, core, seismic data and geological interpretation. Fracture network was described in the reservoir as lineaments (fracture swarms) showing two major fracture trends. The network and its properties, i.e., fracture porosity and permeability, were generated by reconciling seismic, well logs, and dynamic data (well test and PLT). The challenge of the study is to integrate all the input in an efficient and practical way to produce a consistent model between static and dynamic data. As a result, it is expected to reduce the history matching effort. This challenge was solved by an innovative iterative procedure between the static and dynamic models. The static part consists of the calibration of model permeability to match the well test permeability. It is done by comparing their flow potentials, kh. In this analysis the dominant factor in controlling production at each well, either matrix or fracture, was determined. Based on the dominant factor, matrix or fracture permeability was modified accordingly. This way the changes in permeability are kept inline with the geological understanding of the field. The dynamic part was carried out through a full field flow simulation to integrate production data. The flow simulation at this stage was used to match production capacity, i.e. to determine whether the given permeability (matrix and fracture) distribution is enough to produce the fluid at the specified pressure during the producing period of the well. The iteration is stopped once a reasonable production capacity match is obtained. In general, a good match was achieved within 3–4 iterations. The generated reservoir description is expected to substantially reduce the effort required to obtain a good history match. Introduction This paper presents the approach, implementation and results of fracture integration process into a reservoir model. The study is part of a fully integrated reservoir characterization and flow simulation study of an oilfield in the Middle East. A comprehensive integrated reservoir characterization was conducted by considering all available data, namely well logs and cores, geological interpretation, seismic (structures and inversion derived porosity), fracture network, and pressure build up tests. The approach used in the study was a stochastic approach where multiple reservoir descriptions were generated to quantify the uncertainty in the future performance. Reservoir properties for each realization were generated using a geostatistical technique that produces properties, i.e., porosity, permeability and water saturation, consistent with the underlying rock type description. The description was based on core and log data. Additionally, porosity, which affects the permeability description, was also constrained to the seismic derived porosity. The permeability distribution generated by this method was referred to as the core-derived permeability in this paper. Since core-measurement commonly represents the matrix property of the rock, the core-derived permeability mentioned above was also referred to as matrix permeability.
- Asia > Middle East (0.69)
- North America > United States > Texas (0.28)
- Europe > Norway > North Sea (0.28)
- Overview > Innovation (0.60)
- Research Report > New Finding (0.46)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
...SPE 84862 Development of a Correlation for Estimating Gelation in Porous Media Using Bottle Test Measurements Mariyamni Awang and Goh Meng Seng, University of Technology Malaysia Copyright 2003,...anic cross-linking Abstract involves the formation of covalent bonds between functional The bottle test method that is currently used to estimate groups of the polymer, i.e. amides, and the cross-linker,...mer two or more interassociated ionic, radical or molecular and the gelling state given by a bottle test. In this way a better species. The facts the cross linking in Cr 3 /polymer gels can estimation...
...2 SPE 84862 Bottle Test Gel Strength Code A(1) No detectable gel formed. The gel appears to have the same viscosity (fluid)... 30.5 cm long with an ID of 3 cm. The second holder hours, the gel strength code observed in bottle test was H, the was 20.4 cm long with and ID 3.8 cm. Permeability was gel only deformed slightly at the ...
...PV of of 36.44 %. brine injection. While brine permeability of sandpack 5 (5585 Through the bottle test, gel cannot be formed with the mD) decreased to 3648 mD. The gel was washed out from the formulatio...
Abstract The bottle test method that is currently used to estimate gelation only provides a qualitative description and also does not necessarily reflect what happens in a porous media. This paper aims to show a relationship between the permeability of a porous medium that has been injected with a pre gel polymer and the gelling state given by a bottle test. In this way a better estimation of the gel strength in the reservoir can be made. Introduction Polymer gels have been used in oil field for water shut off and sweep efficiency improvement. In recent years, the state of a gel is described qualitatively by the gel strength code, where code A to code J using bottle testing. Robert D.Sydansk studied the gelation rate and gel strength by using bottle testing. However, the bottle testing does not indicate the extent of plugging that occurs in the porous medium. The aim of this study is to develop a relationship between the alphabetic gelation system and the degree of plugging in the porous medium. The most relevant form of testing for gel plugging efficiency proved to be the permeability reduction in porous medium. Theory There are several alternatives to overcome water production problem during the course of oil or gas production. One of them is cementing technology which is aimed at reducing channeling problem behind the pipe to isolate water-producing zone. However, this approach is costly and not entirely reliable. So, gel polymer is preferable and is gaining wider acceptance on account of its cost-effectiveness. Moreover, it is efficient in improving water-oil ratio. Cross-linked polymer utilizing Al as cross-linker introduced by Needham, et. al was successfully applied in Minnelusa reservoir in 1979. Since then, cross-linked polymer technology began to gain popularity in oil industry. In gel treatment, it is best that cross-linked polymer which forms gel penetrates high permeability zone with low oil saturation. This ensures that the subsequent injected fluid be forced to flow to the low permeability zone with high oil saturation. Thus, oil can be displaced in this zone. Metallic cross-linkers can be used to produce gels with anionic polymers. This is done through formation of the ionic bonds between multivalent cations and the negative sites of the polymer. The gels produced through metallic cross-linkers typically have lower thermal stability. Organic cross-linking involves the formation of covalent bonds between functional groups of the polymer, i.e. amides, and the cross-linker, connecting two or more polymer chains. The cross linking agent is a chromic carboxylate complex. The term "complex" herein as an ion or molecule containing two or more interassociated ionic, radical or molecular species. The facts the cross linking in Cr /polymer gels can be described as discrete complexes of Cr implies that they will display chemical reactivity characteristic of Cr coordination complexes. One such reaction is ligand exchange, which refers to the substitution of a ligand bonded to Cr by another, uncomplexed ligand. In the case of Cr /polyacrylamide (PAM) gels, exchange of PAM bonded to Cr for a non-polymeric ligand, L, present in aqueous medium would lead to destruction of the Cr cross link(eq.1).Equation 1 Figure 1 shows the proposed gelation mechanism of cross linking between the acrylamide group and phenol-formaldehyde. The methylolation of a phenol or an acrylamide polymer immates resin formation. A phenol reacts with an aldehyde to form a resin, methylolophenol. Types of bonding, which can occurs between methylophenol and acylamide polymer or between methylophenol and phenol include:ether linkages; methylene linkages; and acetylene linkages. The methylol groups on the methylolated acrylamide polymer are sites for bonding between methyloted acrylamide polymer and phenols.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
...SPE 84896 Alkline/Surfactant/Polymer (ASP) Commercial Flooding Test In Central Xing2 Area of Daqing Oilfield Li Hongfu, Liao Guangzhi, Han Peihui, Yang Zhenyu, Wu Xia...e ASP-flooding expansion field Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435. test,under the condition that the water cut in the central producers is high for a long time,the satisfi...result that the Abstract ASP-flooding oil recovery still can be 19.24%(OOIP) higher The industrial test study on ASP-flooding in the middle part of than the waterflooding is obtained,which fully confirms...
... whose the injection pressure was above 13.0MPa in ASP-flooding system formulation for the indutral test area is the whole area,4 among them could not reach to the allocating 0.2wt%(active)Sa 1.0wt%NaOH 1...g sand of ORSto 303m 3 . 41.The interfacial tension stability and viscosity of the ASP (2)Fluid production rate and water cut decrease,oil ...production system last for more than 3 months. rate increases,seeing obvious response After the chemicals wer...
...SPE 84896 3 response occurs after injection of 0.126PV chemicals,the test area is 0.512µm 2 . The first-class connectivity of channel water cut decrease slowly,and the c...urrently comprehensive sand in the Xingerzhong test area is 29.4%, the one in water cut is 71.8%.This is attributed to the less serious single Beiyidua...nxi test area is 41.7%. The disconnectivity of layer breakthrough,the less areal anisotropy,and the more Xin...
Abstract The industrial test study on ASP-flooding in the middle part of Xinger area of Daqing oilfield is based on a lot of laboratory and numerical simulation studies. By optimizing formulations, the chemical usage in the ASP system reduces significantly, surfactant, polymer, and alkli decrease by one third, nearly one second, and one sixth respectively, with 1.47×10 RMB being saved only for the chemicals. The variation regularity of the ASP-flooding performance is analyzed preliminarily by combining the injection-production profile, the concentration of the produced chemicals, the produced concentration of various ions, and the performance variation (such as the daily fluid production rate, oil production rate and water cut) in the test area with the accurately geological study. At present, the obvious response to increasing oil and decreasing water cut is seen in the test area, 0.22PV ASP system has been injected in the whole test area, and the oil displacement response is seen in 19 producers. The oil displacement response is seen in all 9 central producers, the daily oil production rate increases from 25t before response to 148t, and the daily incremental oil production rate is 123t. The comprehensive water cut decrease from 96.3% before response to 69.9%, decreasing by 26.4 percentage points. The extent of water cut decrease is above 30 percentage points in 5 producers, among which the largest extent is up to 56.9 percentage points. Now, the performance response of the central well area is basically in agreement with the results prediced by the numerical simulation, expecting that the ASP-flooding oil recovery can be 21.52% (OOIP) higher than the waterflooding. Introduction For the ASP-flooding technology of Daqing oilfield, on the basis of a lot of laboratory and numerical simulation studies, ASP-flooding pilot field tests were conducted successfully in the west part of the central area, the central block of Xingwu area, and the area with small well spacing of Daqing oilfield before and after 1993, achieving the good results that the ASP-flooding oil recovery can be 21.4%, 25% and 23.24% (OOIP) higher than the waterflooding respectively. Before and after 1996 two ASP-flooding expension field tests were conducted in the west part of Xinger area and Beiyiduanx of Daqing oilfield, achieving the good results that the ASP-flooding can be 19.24% and 21.04%(OOIP) higher than the waterflooding respectively. Especially for the ASP-flooding expansion field test, under the condition that the water cut in the central producers is high for a long time, the satisfied result that the ASP-flooding oil recovery still can be 19.24%(OOIP) higher than the waterflooding is obtained, which fully confirms that the ASP-flooding mainly improves oil displancement efficiency while enlarging sweep volume. In order to further study the oil displacement efficiency of the ASP-flooding under the condition of the wide spacing, the multiple well group, and the large slug with low concentration, the first industrial ASP-flooding test in the world was carried out in the middle part of Xinger area of Daqing oilfield in 1998 to further verify the economical efficiency of the ASP-flooding techonogy and a complete set of the matching ASP-flooding technology, such as the allocating injection process, the injectivity and the productivity, the performance variation regularity of the oil and water wells, the gas lift process, and the processing technology for the produced water, providing the theoretical and practical basis for the industral deployment of the ASP-flooding. General Situation of Test Area The test area is located in the middle prat of Xinger area of Xingbei oilfield, extending from Fault 202 in the north to Row 30 of Xinger area in the south, and bounding Fault 214 in the east and Well 27 on Row 27 of Xinger area in the west. The five spot pattern is used, the injection-production well spacing is 250m, and the test target is PI21–33. There are 45 producers and injectors altogether, among which the injectors are 17, the producers are 27(the central ones are 9), and the sampling and observation well is 1 (see Fig.1). The associated information about the test area is seen in Table 1.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
...ep is 450-550 mbwpd. Establish aquifer limits - 16 dumpflood wells - the economics are based on - Test injector casing & completion designs achieving the optimum injection rate utilising 16 wells - Esta...ach. Subsurface testing studies indicate a range of injectivities that could result - Establish and test long-term producibility of Zubair in the eventual number of wells required between 11-22. - Establi...DTs before and after injection. - Establish response in oil column to water injection (by - Monitor production rate/watercuts in offset observation layer, sweep/conformance, directionality) wells. - Maximize p...
... Impact of Pressure Maintenance on UG(MO) Future (DMAG/CBIL) Performance & Development Scenarios - Production log tests in the dumpflood well. (PLT) for water breakthrough Two development scenarios have been ...ed on analyzed for its fingerprint to see if the water is Zubair or MO the following: water. - Oil production rate - Plateau Length The following table contains the frequency of tests and - Water ...Production rate surveillance types that need to be implemented on every - Reserves dumpflood well: - Pressur...
...SPE 97624 Umm Gudair Production Plateau Extension, The Applicability of FullField Dumpflood Injection to Maintain Reservoir Pressur...e and Extend Production Plateau R. Quttainah and E. Al-Maraghi, Kuwait Oil Co. Copyright 2005, Society of Petroleum Engin...in reservoir pressure. Abstract Introduction, Geologic Description & History More than 40 years of production has confirmed that the UG (MO) reservoir receives very little natural pressure The project was init...
Abstract More than 40 years of production has confirmed that the UG (MO) reservoir receives very little natural pressure support in some areas. The introduction of a new Production gathering center has increased the field production 6 folds. At current reservoir conditions and production strategy, the production will stay on plateau for only 3 years. This is mainly due to the rapidly falling reservoir pressure. The remedial plan is to initiate a full field water injection project to maintain reservoir pressure. The primary objective of this project was to extend production plateau as long as economically possible. The reservoir pressure for the field, as well as different areas within it, is declining rapidly. The most important cause of this reservoir pressure decline is the high off-take rate (compared with the aquifer influx rate) and the lack of a reservoir pressure support such as water injection. This suggests that the water injection option is needed to support the reservoir pressure and extend the oil production plateau. In this project, many development options were considered. These options can be grouped into three main groups: water injection, infill drilling and combined development options. In the water injection option, comparisons were considered. These options are surface injection vs. dumpflooding, pattern vs. peripheral injection, injection into the oil column vs. injection into the water zone. In the drilling option, comparison between infilling and sidetracking was done. Basically, within each option there was an optimization process, which consists of many sensitivity cases. The purpose behind these many cases is to optimize each option before being combined and get better results than when used alone. For example, in the water injection option, sensitivities were run to see the impact of number and location of injectors. Also, within that case, sensitivities were run to see impact of not achieving a target injection rate. For the infill drilling option, many cases were run to optimize the number of producers. For the combined development options, sensitivities were run to determine best-combined option and to study impact of water injectivity issues. Technical Contributions:Will demonstrate the design of a fullfield water injection scheme to maintain reservoir pressure. Will demonstrate the applicability of dumpflood to re-pressurize a constantly depleting reservoir. Will demonstrate a cost-effective technique to maintain reservoir pressure. Introduction, Geologic Description & History The project was initiated by reviewing all relevant and previous data and studies or projects to recommend an appropriate procedure and set a plan assuming a fullfield dump flood project life. It should be noted that some of the data may not be revealed due to the confidentiality regulations. The primary objective of this project is to maximize the value of umm Gudair field. The Umm Gudair (UG) oil field lies at the northwestern region of the Arabian Gulf within the Arabian basin in the state of Kuwait The field is geographically divided into three smaller sectors, EUG, WUG and SUG. Geologically, the field consists of two anticlines, EUG/SUG and WUG. These two anticlines merge at a shallow structural saddle which links the two structures into a single oil accumulation. Carbonate rocks of the early Cretaceous age form the principle oil producing reservoir in the Umm Gudair field. The Minagish Oolite (MO) carbonates, which is the major oil bearing reservoir unit, is composed primarily of porous grainstones and packstones deposited in a shallow marine shoals and organic build-up on broad carbonate platform, attain a thickness of approximately 400 foot thick original oil column.
- Asia > Middle East > Kuwait (1.00)
- Asia > Middle East > Saudi Arabia (0.75)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.44)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Umm Gudair Field > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Umm Gudair Field > Marrat Formation > Najmah Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Umm Gudair Field > Marrat Formation > Marrat "C" Formation (0.99)
- (3 more...)
Quantifying Remaining Oil by Use of Slimhole Resistivity Measurement in Mixed Salinity Environments - A Pilot Field Test
Sunbul, Ahmed Hassan (Saudi Aramco) | Ma, Shouxiang Mark (Saudi Aramco) | Srivastava, Ashok (Schlumberger) | Hajari, Abdrarasol A. (Saudi Aramco) | Ramamoorthy, Raghu (Schlumberger)
...ining Oil by Use of Slimhole Resistivity Measurement in Mixed Salinity Environments - A Pilot Field Test A.H. Al-Sunbul, SPE, S.M. Ma, SPE, and A.A. Al-Hajari, SPE, Saudi Aramco, and A. Srivastava, SPE, ...pared for presentation at the SPE International Improved Oil Recovery learnt from this pilot field test of more than 30 wells. Conference in Asia Pacific held in Kuala Lumpur, Malaysia, 5-6 December 200...rcial purposes without the written consent of the Society of Petroleum Engineers is optimizing oil production and water management. Since the prohibited. Permission to reproduce in print is restricted to a pr...
...include an in-line centralizer just above the bottom nose, as shown in Fig. 2. In this pilot field test of SIRT RSM, formation water was characterized mainly using bottomhole samples. Objectives. Evaluat...ion of the SIRT in Saudi Arabia was started in 2002. A field pilot test was initiated in 2003, and, SIRT TOOL EVALUATION since then, more than 30 SIRT RSM jobs have been c...ompleted in the field. The objectives of this paper are: Before the SIRT RSM field pilot test, the SIRT tool was evaluated and field tested in well XU-1512; a newly drilled - To summarize lesso...
...ier. borehole signal, we see that all the output resistivities are Practicality. Unlike traditional production logging tools almost identical. that are logged with monocables which have typical OD of These sen...r shut-in pass, the well should be logged at a higher flow rate and a conditions, it was decided to test SIRT under flowing ...production log survey should be done at the same flow rate to conditions, to minimize borehole fluid invasion...
ABSTRACT Quantifying remaining oil in waterflooded reservoirs is critical for successful reservoir management.For wells with narrow producing tubings, the slimhole induction tool is used because of its deep depth of investigation (DOI).Mixed formation water salinity is characterized using bottomhole samples. Ideally, running an induction tool requires non- or low-conductive borehole fluid uniformly distributed in the borehole. This may not always be achievable under production conditions.In this study, the following were investigated:The slimhole induction tool was first tested in a newly drilled well and its measured data were compared with that of the standard induction log. The tool was run in a borehole under both flowing and shut-in conditions. In this case, the effect of borehole fluid distribution was evaluated. The multiple DOI capabilities of the slimhole tool were used to study the phenomenon of borehole fluid re-invasion during both flowing and shut-in conditions. From this study, the following were concluded:Slimhole induction measurement agrees well with standard induction measurement. Mixed formation water salinity can be characterized using bottomhole samples and production logs. The following borehole characteristics affect shallow DOI measurements, but not deep DOI measurements:Borehole rugosity. Borehole fluid contact and conductivity. Borehole fluid re-invasion Guidelines for running slimhole induction log and collecting bottomhole samples for quantifying remaining oil in mixed salinity environments are summarized based on experiences learnt from this pilot field test of more than 30 wells. INTRODUCTION Saturation Monitoring with Resistivity Logging. For reservoir management, quantifying remaining oil is critical for optimizing oil production and water management.Since the majority of producing wells in X field, Saudi Arabia, are completed openhole, one of the main concerns for reservoir saturation monitoring (RSM) of openhole wells is the effect of borehole fluid invasion or re-invasion on shallow DOI RSM techniques; such as nuclear (sigma or carbon-oxygen) log measurements. For newly drilled wells, water-based mud filtrate invasion results in higher near wellbore water saturation, Sxo, compared with the connate water saturation, Swc.[1]During well cleaning and production, capillary hysteresis prevents Sxo equaling Swc.[2]Even if Sxo can be reduced to the original Swc, the process may be very slow due to low water relative permeability (krw).When Swc approaches to the residual water saturation, Swr (sometimes also referred as irreducible water saturation, Swi), it may take years for Sxo to be restored to Swc.[3] For wet producers, on the other hand, produced water in borehole may reinvade back into the formation during well shut-in.Wellbore oil re-invasion can also occur (probably due to gravity segregation once a producing well is shut-in) and has been observed in our field operations. [4] All these wellbore fluids re-invasions cause near-wellbore reservoir saturation that is not representative of reservoir saturation.
- Europe > United Kingdom > North Sea > Central North Sea (0.71)
- Asia > Middle East > Saudi Arabia (0.50)
- North America > United States > Texas (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
Hybrid Testing Technique Results in Successful Well Test and Completion of Low Permeability, HP/HT Sour Crude Reservoirs - A Case Study from Kuwait
Reji, E.C. (Kuwait Oil Company) | Al-Awadi, Mohammed (Kuwait Oil Company) | Al-Medhadi, Fahed (Kuwait Oil Company) | Kaura, Jiten (Halliburton Energy Services, Inc.) | Clayton, Robert (Halliburton Energy Services, Inc.)
...SPE 84858 Hybrid Testing Technique Results in Successful Well Test and Completion of Low Permeability, HP/HT Sour Crude Reservoirs - A Case Study from Kuwait E.C. Re...on Energy Services, Inc. Copyright 2003, Society of Petroleum Engineers Inc. would be required to test these zones efficiently. This paper was prepared for presentation at the SPE International Improve...iety of Petroleum Engineers, its officers, or members. Papers presented at 4. The operation of the test-string, annulus-pressureresponsive SPE meetings are subject to publication review by Editorial Com...
...t (CTU) for acidizing. hookwall packer. - A well kick-off operation with CTU and diesel in the The test was set up with a cased-hole RCT string with the event well would not flow naturally. TCP guns in t... the wellbore storage effects while the gauges record the build-up pressures and temperatures would Test Objectives cut down the build-up time and the rig time. The primary objective for this vertical, e...xploration well was to - Capturing representative downhole reservoir fluid test for moveable hydrocarbons in the two deep Jurassic samples as part of the string to later carry out...
...the 7-3/4-in. casing section, a pressure transmission needed to operate the APR tools. conventional test was required to meet the objectives. The At higher mud weights and higher temperatures, the barite ...er using During design of the tool string, maintaining safety and well TCP guns with the drill stem test (DST), it should be known control during every stage of the operation at the wellsite were that the...on fluid is compatible with the mud system in the priorities. In order to have a safe and effective test, it was wellbore before the cushion is spotted. This was mentioned important that special considera...
Abstract The development of light-oil reservoirs in Kuwait has become increasingly more important for maintaining the quality of exported crude. This is due to the fact that producing light-oil reservoirs has proven to be not only a necessary link for maintaining the oil production from this area but also for increasing it. As a result, efficient testing of the light-oil reservoirs has become paramount in importance for overall well and field development. The reservoirs in Kuwait are low permeability, high pressure/high temperature (HP/HT) and sour. In earlier wells, the strategy had been to perforate these formations balanced or slightly overbalanced, in mud, with through-tubing guns. Results from testing in several wells indicated that if they could be perforated under-balanced, the formations would yield better results since this method would allow better penetration and perforation cleanup. A number of reservoirs are stacked horizontally and range from typically conventional to fractured limestone. In view of the corrosive nature of the fluids present, one of the primary efforts in the testing of these wells had to be directed toward keeping the number of wireline and coiled-tubing operations to a minimum without compromising the testing objectives. Since it was necessary to test multiple objects in the exploratory wells individually, special effort was focused on determining methods that could effect a reduction in the testing period for each object. By reducing individual testing times, Kuwait Oil Company felt that the overall savings would be significant. Several areas were identified that would require special consideration. This paper will discuss these areas (listed below) and how the challenges they presented were addressed:Modifications to retrievable completion test (RCT) tools and tubing-conveyed perforating (TCP) equipment that would be required to test these zones efficiently. The challenges associated with designing and carrying out the tests. Ongoing modifications in the testing methodology to overcome the testing challenges. The operation of the test-string, annulus-pressure-responsive components in the heavy oil-based mud and the difficult wellbore conditions. How the problems of shaped charge performance in the naturally fractured formations with unusually high compressive strength and very low matrix permeability and porosity were resolved. The modifications to tools and methods allowed the goals of the operator and service provider to be met. Background Fig. 1 shows a typical completion schematic for the formations intercepted in the deep Jurassic layers of west Kuwait. Monobore completions are normally used. The reservoir evaluation technique followed by the Kuwait Oil Company in the wells of west Kuwait follows:Drill and complete well in the zone of interest Mobilize and rig-up wireline perforation unit and production testing spread Perforate the well using through-tubing guns with mud caps Flowtest the well through the production testing unit on location. While the above procedures were satisfactory, it was felt that that better well performance and completion efficiency could be achieved by a step change in the formation evaluating technique. Other options were reviewed. The first change planned was to test the well using a retrievable completion test (RCT) string. The reasons for making this change were due to the testing methodology adopted and the changes made to the procedural operations. These changes follow:Since the wells were deep with a telescopic casing design, and the reservoir was sour, the decision was made to test using completion tubing instead of the drill string. A Christmas tree was to be used as opposed to a surface test tree with testing performed through the blowout preventers (BOPs) as in a regular test. Safety was the primary driver for using a Christmas tree as the well had H2S and high pressures.
...SPE 97694 Improving Hydrocarbon Production Rates Through the Use of Formate Fluids - A Review J.D. Downs, SPE, Cabot Specialty Fluids Ltd.; S...d The formates are particularly valued as drilling and literature over the past 12 years about well production rates completion fluids in challenging operational environments after drilling and/or completing wi...ance has been degraded and formate. This insight gave Shell the novel ability to formulate the well production rates have been unexceptional or below simple water-based drilling and completion fluids with expec...
...r the and the pore pressure, necessitating the use of a drilling fluid disparity between laboratory test results and field experience with low ECD. Traditionally the Gullfaks wells had been could be that ...ests are typically performed in completed with liners and selective perforating. Due to rate linear test cells, which tend to promote a high level filtrate limitations caused by sand ...production and water breakthrough, invasion from brine-based fluids at high overbalance, whilst in the complet...
...) (-35.7%) DIF [0.30ml] - 25% increased ROP Optimised 3.64 2.27 - 100% success rate in running production liner 3B Formate 8.388 7.47 (-51.3%) (-69.6%) DIF [0.17ml] Once the wells had reached TD, the u...o remove the majority of bridging agents and drill solids. The processed Table 1: Huldra core flood test results - after fluid was then used as a completion fluid during the drawdown (SPE 73766) completi...on phase. The wells were put on production with a typical ...
Abstract Formate fluids have unique physico-chemical properties that make them the ideal drilling and completion fluids for challenging well construction projects where extraordinary fluid performance is critical for economic success. They have been used in more than 400 wells across the world since their commercial introduction in 1993. This paper reviews what has been published in the oilfield literature over the past 12 years about well production rates after drilling and/or completing with formate fluids. The conclusions of the review arethe special properties of formate fluids facilitate the creation of long high-angle wells that improve reservoir access and inflow area; the formates tend to minimize formation damage; the use of formate fluids generally delivers wells with productivities that exceed expectations. The published field case histories clearly show that formate fluids can only show their true performance potential when formulated with low levels of solids. When operators have experimented with the addition of weighting solids to formate fluids the drilling performance has been degraded and the well production rates have been unexceptional or below expectations. Some of the information disclosed in the literature opens to question whether the use of linear core flooding is an appropriate laboratory test method for predicting the likely impact of formate fluids on well productivity. Introduction "Formate fluids" is the collective name given by the oil industry to aqueous solutions of the alkali metals salts of formic acid. The formates are revolutionary in the sense that they can be used to create solids-free or low-solids drilling and completion fluids with densities of up to 19.2 lb/gal (2.3 SG). High-solids drilling fluids containing formates will have inferior performance and should not be described as formate fluids. Prior to the discovery of formate fluids it had been impossible to formulate solids-free drilling fluids with densities higher than 12.5 ppg (1.5 SG); the traditional high-density brines were just not compatible with the drilling fluid polymers. At least 400 wells have been drilled and/or completed with formate fluids since their introduction in 1993 and they have been the subjects of more than 30 SPE papers. The remarkable properties 1–4 of the formate fluids are exploited by the oil industry to drill and complete wells that are optimized in terms of:Cost/Value Operational Time Productivity Lifetime Environmental impact Reduced liability and risk The formates are particularly valued as drilling and completion fluids in challenging operational environments such as:High temperature/high pressure (HT/HP) Extreme well configurations (ERD, TTD, CTD) Sites of ecological sensitivity
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- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/19 > Brigantine Field > Rotliegend Sandstone Formation (0.99)
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Further Evaluation of Microbial Treatment Technology for Improved Oil Production in Bokor Field, Sarawak
Sabut, Bangkong (Petronas Carigali Sdn Bhd) | Salim, Mat Ali Hj. (Petronas Carigali Sdn Bhd) | Hamid, Ahmad Sharby A. (Petronas Research & Scientific Services Sdn. Bhd.) | Khor, S.F. (Petronas Research & Scientific Services Sdn. Bhd.)
...and already biodegraded crude oils were left with no light perform the desire activity to boost oil production. Since the hydrocarbons, therefore the microbes reacted with the microbes used are all natural and ...ing injection and handling the weight hydrocarbons. produced fluids when the wells were returned to production. The kinematic viscosity results of the post-treatment crude oil Pre-Treatment samples are shown i... viscosity. Here the bio-enzymes and metabolites After 7 days of shut-in period the individual well production produced by the microbes are able to breakdown the performances were closely monitored for 6 months...
...own in Figure 8. However, the gross also can be observed for the wells B-5, B-7 and B-8 with liquid production, apart from the initial spike after the well higher reduction observed at room temperature than at ...resumed production, responded positively. The recorded elevated temperature. However, there is no viscosity change ave... observed for the well B-6 (results not shown). total gain on the project. (3) Emulsion Separation Test Well-B7 The crude oil from the treated reservoir in Bokor field is Figure 9 shows that both the gr...
...s favorable, based on the positive changes in oil properties October 2001. causing an increased oil production in a majority of the wells 3. PRSS, "Feasibility Studies of Microbial EOR treated. For more detail ...PRSS-TCS-06-99-02, summarized as follows; Nov 1999. 4. PRSS, "Feasibility Studies of Microbial EOR Production Performance Results Mechanisms and Potential Pilot Application in Bokor ...Production increase observed is mainly due to high Field, Sarawak", Report no.: PRSS-TCS06-00-03, gross ...
Abstract This paper depicts the laboratory results as well as the well production performances of five oil wells that were treated with microbial technology using 'huff & puff' method. It is the second microbial stimulation project in Bokor field after the pilot project implemented in July 2000. However, in this project the wells selected for the treatment were not very much depleted as compared to the three pilot wells, which were very much depleted in their production. Several types of laboratory analyses conducted on the crude oil samples showed encouraging results in favour of this technology whereby there is an improvement in crude oil flow characteristic. This is due to the degradation of heavy molecular weight into lighter hydrocarbons upon reaction with them icrobes. Crude oil rheological study conducted on post-treatment samples concluded an enhancement in crude oil mobility in a majority of the wells treated. A reduction in the emulsion stability of the crude was also observed after treatment. Post treatment production performance monitoring for all the five wells have shown positive response to treatment with better oil gained per well. Collectively, the five wells produced an average of 111 bopd per well of incremental oil, compared to 90 bopd per well incremental in the pilot project over five months post treatment monitoring period. Nonetheless, these favourable results were largely overshadowed by the high variability between good responding wells and the poor responding wells. Detail explanations to describe the well responses due to treatment were provided based on laboratory analyses results and well production performances. Introduction In July 2000, the pilot project of microbial treatment was implemented in Bokor field, Sarawak. Three strings namely, B-1, B-2 and B-3 were treated with microbial cultured products using 'hulf and puff' method. The field description, reservoir fluid characteristics and results of the project are well documented in the previous paper. In the pilot project, the average oil gain of 270 bbl/day (47% incremental)was reported over the 5 (five) months post microbial treatment. Analysis on produced fluids after treatment showed that the crude oil quality was enhanced with reduced viscosity and emulsion stability. Hydrocarbon compositional analysis indicated that there was an increase in the solubilisation of heavy components and breakdown of high molecular weight into low molecular weight components. Bacteria analysis conducted on produced water showed negligible SRB activity in the reservoir. The encouraging results of the pilot project has then justified for as pin-off project and an additional 5 (five) wells from the same reservoir in Bokor were then identified and selected for similar treatment. However, in this project, the wells selected for microbial treatment were not very much depleted as compared to those 3 (three) pilot wells, where productions have been depleted at the time of treatment. Field Description The Bokor field is located in the Baram Delta Area which is about 40kilometers offshore Lutong (Miri) at a water depth of 67 meters below msl. Stacked and laterally continuous sand-shale sequences characterize the field stratigraphy and are deposited in a coastal plain to fluviomarine environment. Based on core measurements, porosities range between 15% and 32%, while permeabilities range from 50 mD to 4000 mD. Oil gravities range from 19° API to22° API in the shallower reservoirs (1500 Ft. Ss - 3000 Ft. Ss) to 37° API atthe deeper reservoir (6300 Ft. Ss). The reservoirs in the Bokor field can be divided into two main groups, i.e. the main reservoirs (A-F) and the deep reservoirs (H-L). In this project, the treatment was focused on the A reservoir, which is the major reservoir of the field.
...SPE 97687 Numerical Studies of Oil Production from Initially Oil-Wet Fracture Blocks by Surfactant Brine Imbibition B. Adibhatla, SPE, X. Sun, S...brine phase oil, (ii) water-wettability of the solid surface due to dissolution can improve the oil production by lowering the oil-water of the ion pairs into the oil phase and micelles, (iii) interfacial tensi...llarity and gravity help to improve oil anionic surfactants (which are usually priced at 1 US$ per production: in the early stage of the ...
... any component among different phases. Under this The effect of alkaline surfactant solution on oil production assumption, Eqs. (6) and (7a) - (7d) are closed by the phase from an oil-wet fracture block is stud...
... cell. using the numerical models discussed earlier is developed. It We estimate errors of our oil production volume on this is used to simulate the laboratory experiments. basis and add that to the separated ...
Abstract Little oil can be produced from fractured oil-wet reservoirs by water flooding. Introduction of surfactant into the brine phase can improve the oil production by lowering the oil-water interfacial tension (IFT) and by altering the wettability of the matrix block to water-wet. A 3-D numerical simulator is developed to model this process. The capillary pressure, relative permeability and residual saturations of both phases are considered as functions of IFT and wettability, which are correlated to the surfactant and salt concentrations based on the data obtained from laboratory experiments. The mass balance equations are solved with a fully implicit scheme. Numerical simulation matches the experimental data obtained for alkaline surfactant imbibition. Simulation results indicate that both capillarity and gravity help to improve oil production: in the early stage of the production, capillarity is found to be the major driving force, and in the later stage, gravity dominates the production. Surfactant diffusion into the matrix block leads to IFT and wettability alterations which in turn lead to oil mobilization. Oil recovery by the time surfactant completely diffuses into the matrix block is found to be about 30% of the total recovery. As matrix block height increases, or surfactant alters wettability to a lesser degree, or permeability decreases, oil production rate decreases. Introduction Carbonate reservoirs are mostly naturally fractured and are oil-wet or mixed-wet.[1,2] Recovery factor in these reservoirs depends on matrix permeability, wettability, fracture intensity, and fluid properties.[3] Water flooding is an effective technique for fractured reservoirs if the matrix is water-wet. The positive capillary pressure helps in spontaneous imbibition of water into the matrix leading to oil recovery. But since most of the carbonate reservoirs are oil-wet/mixed-wet in nature, capillary pressure is predominantly negative and water flooding does not lead to a significant amount of oil recovery from the matrix. Surfactant flooding (or "huff-n-puff") techniques are being developed[4–18] to improve oil recovery from oil-wet/mixed-wet, fractured carbonate formations and are the subject of this study. Austad and coworkers have conducted a series of studies[10–13] on oil recovery from oil-wet chalk cores by use of cationic surfactant solutions. They have shown that cationic surfactants, such as DTAB, are quite effective (recovery ∼70% original oil in place, OOIP) in imbibing water into originally oil-wet cores at concentrations greater than their CMC (∼1 wt%). The imbibition mechanism is proposed asthe formation of ion pairs by the interaction between surfactant monomers and adsorbed organic carboxylates from the crude oil, water-wettability of the solid surface due to dissolution of the ion pairs into the oil phase and micelles, countercurrent imbibition of brine due to positive capillary pressure. The imbibition rate increases with temperature and decreases with connate water saturation. The interfacial tension between the surfactant solution and oil are not low (> 0.1 mN/m). Austad et al.[14–16] identified on several inexpensive cationic surfactants of the form C10NH2 and bioderivatives from the coconut palm, termed Arquad and Dodigen (priced at 3 US$ per kg), which were able to recover 50 to 90% of OOIP. The higher cost of cationic surfactants compared to anionic surfactants (which are usually priced at ∼1 US$ per kg) and relatively higher concentration required (∼1 wt %) has encouraged other to evaluate anionic surfactants for fractured carbonates[17–18] in the presence of a low concentration potential determining ions (∼0.3 M Na2CO3). They found that interfacial tension (IFT) can be lowered to ultralow levels (∼10–3 mN/m), wettability can be changed to intermediate wettability, and imbibition can be improved (>50% OOIP) by the use of very dilute (0.05 wt %) anionic surfactant/alkali solutions.
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