NotesNov-09NOTES:The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetroThe papers relating to reservoir engineering have been catergorised for inclusion on the reservoirengineering.org.uk websiteThe affiiations searched were;Total No PapersReservoir Engineering RelatedBP551175Shell575279Chevron482238ConocoPhillips19168Marathon5537Total255129Schlumberger1130563Imperial College, London9553Heriot Watt University, Edinburgh235175(Anywhere in Article)Total35691717Total number of papers published post 2005 =10,00035% of papers published categorised

SurveillanceOrganisationSourcePaper No.ChapterSectionSubjectTitleAuthorAbstractBPSPE101762Surveillance4D Micro gravityPrudhoe BayResults of the World's First 4D Microgravity Surveillance of a Waterflood--Prudhoe Bay, AlaskaJ.L. Brady, SPE, BP Exploration Alaska; J.L. Hare, Zonge Engineering and Research Organization; J.F. Ferguson, University of Texas at Dallas; J.E. Seibert, Seibert & Associates; and F.J. Klopping, T. Chen, and T. Niebauer, Micro-g LacosteSummary The worlds first 4D surface-gravity surveillance of a waterflood has been implemented at Prudhoe Bay Alaska. This monitoring technique is an essential component of the surveillance program for the Gas Cap Water Injection (GCWI) project. A major factor in the approval process for the waterflood was to show that we could monitor water movement economically where a very limited number of wells penetrated the waterflood area. The drilling of numerous surveillence wells to monitor water movement adequately would have been cost-prohibitive. Field surveys now show conclusively that density changes associated with water replacing gas are being detected readily with high-resolution surface-gravity measurements. The gravity methods used to monitor the waterflood include time-lapse (4D) measurement of surface gravity over the reservoir followed by inversion of the 4D signal for mass-balance calculation and flood-front detection. This paper will focus on field results of time-lapse surface-gravity surveys. Differences in the gravity field over time reflect changes in the reservoir-fluid density. The inversion procedure was formulated and coded to allow for various constraints on model parameters such as density total mass and moment of inertia. The gravity survey was designed to permit the inversion for reservoir mass distribution with resolution on the order of hundreds of meters in the presence of uncorrelated noise of reasonable magnitude (12-Gal standard deviation). Time-differenced gravity-survey results clearly show an increase in surface gravity that is a result of the injected-water mass. Density-change maps deduced from measured gravity change show that water movement is reasonably similar to the reservoir simulations and to the water detected in observation wells. The overall ultimate gravity signal is predicted to increase to approximately 250 Gal ultimately resulting in accurate maps of the water movement. Introduction This paper discusses the use of surface-gravity measurements as a reservoir-surveillance technique specifically to monitor the gas-cap water injection in the Prudhoe Bay oil-field. The fundamental problem of monitoring the gas-cap water-injection project is the small number of monitoring wells and the lack of producing wells in the gas-cap area of Prudhoe Bay. Distances between some monitoring wells are greater than 10 000 ft (3048 m) and years will be required for the injected water to propagate to these distances. Too few wells exist to monitor the water movement adequately with conventional downhole-logging techniques. To address this problem the Prudhoe Bay surveillance program uses a combination of conventional downhole logging in existing wells and 4D surface-gravity monitoring. The major monitoring concern with the waterflood is ensuring that water added in the gas cap does not flow downdip prematurely into the oil-producing portions of the field in which it could interfere with a highly efficient gravity-drainage mechanism. Surface-gravity instruments measure the Earths gravitational field at a specific point or station. With an array of these measurements local structural traps stratigraphic traps or fluid movement can be identified provided that there is a sufficient density contrast between the feature of interest and the surrounding rock. The surface-gravity technique can be applied to any field depending upon the reservoir thickness size depth of burial porosity and the density contrast between the fluids. The surface-gravity technique requires that several time-lapse gravity surveys be made over the life of the field. The first survey should be performed before any change in the fluid volumes to obtain baseline data. The baseline survey can be subtracted from future gravity surveys to obtain the gravity anomaly associated with the change in fluid volumes. The technique assumes that any other time-dependent gravity changes can be accounted for either by measurement or by modeling and that noise caused by the measurement process and unmodeled (near-surface) density changes have tolerable characteristics. The GCWI project at Prudhoe Bay produces an increasing positive gravity anomaly because of the added mass over time caused by water replacing gas in the pore space. Density variations from local geology and topography that do not change with time are effectively canceled when gravity data from different time epochs are differenced. The time-differenced or 4D gravity signal is then inverted to obtain a reservoir-density-change model. This change in reservoir density represents the waterflood progression. The gravity signal of interest is the observed gravity corrected for instrument drift solid Earth and ocean tides and polar motion and atmospheric-pressure changes. Topographic changes in the vicinity of the stations are likely on permafrost and bay ice over periods of years (1-cm elevation equals 3-Gal gravity) so that the elevation difference contributes free air and Bouguer (i.e. mass) correction terms to the gravity difference. The 4D survey is possible only through the use of high-accuracy global positioning system (GPS) and a Gal-precision gravimeter. The Micro-g Lacoste A-10 absolute-gravity meter is used to measure the acceleration of a falling mass in a self-contained experiment which can be tied rigorously to standards of length and time. Each gravity observation is the result of approximately 1 000 repetitions of this simple experiment. Each station observation is independent of all other stations and instrument calibrations unlike conventional relative-gravity-meter surveys. Survey parameters must be duplicated as closely as possible from year to year in order to minimize survey error. The stability of permanent-station monuments is poor in permafrost environments and is impractical on bay ice; therefore station recovery must be accomplished by navigation using real-time submeter GPS (Parkinson and Enge 1996). Relocating stations to within 1 m permits neglecting a latitude correction (the gravitational latitude effect at 70 north is less than 1 Gal for northing differences of less than 1 m) and to avoiding an interpolation operation before time-differencing the gravity data. The centimeter-precision location can be obtained by using real-time kinematic or post-processed carrier-phase ambiguity resolution (rapid static") GPS methods. Multiple base stations can be used in network-averaged solutions for increased accuracy. Both the GPS and gravity data are usually obtained within a 20-minutes-long station occupation. Extensive gravity modeling has been performed using reservoir simulations that includes simulated noise with various magnitudes and characteristics to determine tolerable noise levels to ensure a successful monitoring program at Prudhoe Bay (Hare et al. 1999). In addition to this four field test surveys have been completed since 1994 to verify the accuracy of both the time-lapse gravity data and the GPS gravity-station-location data. It has been established that time-lapse gravity data can be obtained at a sufficiently low noise levels to ensure that the injection water can be monitored properly. The Prudhoe Bay reservoir is buried at approximately 8 200 ft (2500 m) in the gas-cap region of the field and has a maximum gas-water-density contrast of 0.12 g/cm3. Even at this depth Prudhoe Bay is a good candidate for the surface-gravity monitoring technique because of a reservoir thickness as great as several hundred feet and a high porosity. Previous publications have included a description of the reservoir-simulation models and the resultant density contrast; inversion of the simulated surface-gravity anomaly to determine the degree to which water-movement progression can be monitored; and a review of the four gravity- and GPS-data-acquisition field tests that were performed on the bay ice and tundra in March of 1994 1997 2000 and 2001 (Hare et al. 1999; Brady et al. 1995a 1995b 2002a 2002b 2005). This paper will discuss the results of the two baseline surveys performed in the winters of 2002 and 2003 and the results of the first time-lapse gravity survey of water movement after water injection began. This 2005 survey clearly shows that the gravity anomaly created by injecting 340 million bbl of water can be detected and mapped."Heriot Watt UniversitySPE115028Surveillance4D Micro gravityWater EncroachmentUtilizing 4D Microgravity To Monitor Water EncroachmentMohammed J. Alshakhs, SPE, Heriot-Watt University & Saudi Aramco; Erling Riis, University of Strathclyde; Robin Westerman, Heriot-Watt University; Stig Lyngra, SPE and Uthman F. Al-Otaibi, SPE, Saudi AramcoAbstract The common wisdom is that gravity methods have limited application in the oil industry although they have long been available. The main use of gravity has been for exploration purposes. 4D microgravity monitoring is another new promising gravity application to monitor changes of fluid contacts. Some successful 4D monitoring surveys have been conducted in the industry revealing that this technique is a proven technology in monitoring of gas-water contacts. This paper studies the ability of microgravity to capture movement of the injected water in a giant carbonate field. The oilwater case is more difficult due to the significantly lower density contrast as compared to the gas-water case. Monitoring water floodfront in the field is a key factor in applying successful reservoir management practices to maximize recovery and prolong the field life. The monitoring of inter-well fluids would characterize any pre-mature water breakthrough to allow planning and design of appropriate remedial well interventions. The current applied monitoring tools such as carbon-oxygen and resistivity logs can only detect fluids near to the wellbore due to their shallow radius of investigation. For the study field 4D seismic cannot be used for fluid movement detection due to issues related to formation acoustics impedance and data quality. The study has shown that surface microgravity monitoring could successfully detect the inter-well fluid changes due to water injection with a high precision tool (0.01 microgal). It also shows that microgravity monitoring can capture water bodies located hundreds of meters away from the location of the 4D measurement. Introduction The monitoring of inter-well fluids would characterize any pre-mature water breakthorough to allow planning and design of appropriate remedial well interventions. The conventional monitoring tools such as NMR carbon-oxygen and resistivity can only detect the water flood front near to the individual wellbore due to their short radius of investigation1. The radius of investigation of NMR and carbon-oxygen tools is limited to few inches while the resistivity tools can detect up to few feet into the reservoir. The resistivity water saturation calculation is also dependent on several often uncertain petrophysical input parameters like m n and Rw. If the salinity of the original formation water and the injected water differs a mixed reservoir water salinity environment is generated which can add a particular challenge in defining the Rw input as the salinity may change with depth in each individual producing well. It is apparent that available shallow radius of investigation tools lack the needed reservoir coverage to map the reservoir enchroachment over time. Only after water is observed in the well can the location of the floodfront be mapped with any certainty. The techniques that provide adequate reservoir coverage such as 4D seismic or cross-well resistivity may not provide the required resolution and accuracy in saturation estimation. In the study field 4D seismic cannot be used due to a weak 4D response. The small change of acoustic impedance from oil-bearing formation to water bearing formation is responsible for the weak 4D seismic effect complicated by surface statics. The new alternative techniques such as cross-well resistivity have some operational constraints pertinent to the well completion. Gravity methods have simple equations and robust nature of measurement which give them greater advantage over other methods such as seismic2 3. However the non-uniqueness problems restricted gravity applications in the oil industry4. The main use of gravity is for exploration purposes when seismic surveys are not applicable such as when a salt diaper is present5. In the latter situation its objective is to assess in the processing imaging and/or interpretation of seismic. Time-lapse microgravity is a new evolving gravity method that is used to monitor fluid changes with time in the reservoir. The survey should have an array of surface measurements covering the study area with reasonable spacing between each measurement. Borehole microgravity measurements can also be used in the survey to aid in understanding the gravity signal.CHEVRONSPE116916Surveillance4D SeismicEnfield FieldIntegrating 4D Seismic Data with Production Related Effects at Enfield, North West Shelf, AustraliaAmna Ali, SPE, Ian Taggart, SPE, Benjamin Mee, Megan Smith and Andre Gerhardt, Woodside Energy Ltd. and Laurent Bourdon, Shell Development (Australia)Abstract The Enfield field has a 160 m oil column located between a medium sized gas cap and a water/leg aquifer system. Enfield is undergoing an active water-flood utilizing both up-dip and down-dip water injection. The water-flood reservoir management of such a field requires timely information concerning reservoir pressures water-flood sweep and movement of gas and water contacts. Conventional reservoir monitoring practice obtains this information by monitoring at the wellbore. Such approaches require significant time and water-cut development to determine how the reservoir and water-flood is performing and provide little spatial information as to how the water-flood is affected by faults preferential pathways and structural variation. 4D seismic methods represent a powerful tool to assist reservoir management. This work describes the planning implementation of an early 4D program for the Enfield water-flood and history matching process. Pre-development feasibility work indicated that Enfield had rock properties favourable for 4D monitoring as reservoir sands are acoustically soft and identifiable with seismic amplitudes. Post-production early 4D monitoring has provided unique and timely insight into water movement both within the reservoir and through active fault networks that wellhead data alone would not provide. This work has shown the benefit of 4D in the following areas; tuning of injected water flows to a northern fault/aquifer system locating new injector producer pairings improved utilization of geologic and seismic barrier and baffle features into the history matching process and finally showing how the seismic response to up-dip water injection around a key injector was more subtle and supported the choice of imbibition relative permeability relationships and trapped gas saturations. Validation of insights was provided by the use of synthetic seismic modeling of simulation results. Introduction The Enfield field is an active water-flood project located in production permit WA-28-L some 40km north of Exmouth offshore Western Australia and is jointly owned by Woodside Energy Ltd (60% Operator) and Mitsui Australia E&P Ltd (40%). Water depth across the field varies from approximately 325m in the east to 550m in the west. The Enfield oil reservoirs are within the Upper Jurassic to Lower Cretaceous age Macedon Member comprising generally clean high permeability unconsolidated sandstones contained within the crest of a north-easterly plunging fault bounded terrace that covers approximately 16 km2 with a total relief of 350 m. The Enfield trap was created by cross fault juxtaposition of the relatively thin sandstone intervals encased in a thick marine shale sequence. The trap is characterised by structurally conformable high seismic amplitudes associated with the hydrocarbon-bearing reservoir interval. Enfield is highly faulted with a gentle structural dip of 3.SHELLSPE128362Surveillance4D SeismicFeasibilityTime-Lapse Feasibility Studies of Two Fields in the Niger DeltaFrancesca Osayande and Omuvie Ugborugbo, Shell Petroleum Development Company of NigeriaAbstract Time-lapse Feasibility Studies were carried out for two producing fields in the Niger Delta to assess the probabilities of success of acquiring 4D surveys. The two fields are located within onshore Niger Delta. Agbada field is located on land 100km North West of Port Harcourt Nigeria. The field was discovered in 1960 and has been producing since 1965. To date some 66 wells have been drilled in the field. It has a STOIIP of about 1.5 billion barrels. Current estimate of undeveloped hydrocarbon reserves stand at Expectation Volume of 285 MMbbl and 0.8 Tscf. However the field is experiencing high water cut and declining production. Agbada Field is covered by several vintages of 2D lines and one vintage of higher quality 3D seismic data that was acquired in the 1993. Kolo Creek field is located within the swamp 110km South West of Port Harcourt Nigeria. The field was discovered in 1961 but started production in 1973. It has a STOIIP of 495 MMSTB and an FGIIP of 1.3 TCF. Total Oil production to date is 254MMstb representing 45% of the STOIIP; and there has been no gas production. This field is also experiencing declining production and high water cut. It is also covered by several vintages of 2D lines and one vintage of higher quality 3D seismic data that was acquired in 1997. For each of these fields it was desired to determine whether time-lapse signals will be detectable and to ascertain the optimum time in which to carry out a time-lapse monitor survey. The history matched dynamic simulation models for each field were converted to acoustic properties through a suitable rock model and resultant acoustic impedances were calculated. Synthetic seismograms were subsequently generated for several time steps and analyzed for production-induced 4D signals. The impact of various levels of random noise on the 4D response was also evaluated. The results from both of these studies demonstrated that even in the presence of significant random noise production induced 4D changes should be observable if the monitor seismic survey is acquired in or beyond 2006. These results will be discussed.TOTALIPTC11640Surveillance4D SeismicFeasibilitySeismic Monitoring Feasibility on Bu-Hasa FieldMarvillet C., Hubans C., Thore P., Desegaulx P, TOTAL, Al-Mehairi Y.S., Shuaib M., Ali Al Shaikh ADCOAbstract Summary A 4D seismic feasibility study has been performed on carbonate reservoirs of the Bu Hasa field onshore Abu Dhabi. It concludes to the feasibility of the method as a reservoir injection monitoring tool an interesting result when several recent papers [1] have suggested that 4D seismic may not be applicable to Middle East carbonate reservoirs due to their rock physics characteristics. 2D full wave equation and 3D convolutional modelling approaches have been combined in this study in order to maximize the reliability of the predictions while optimizing the cost effectiveness of the study. Because the assessment of repeatability noise indicated a realistically irreducible threshold for high resolution 4D surface seismic and a possible limitation for WAG monitoring a 4D well seismic exercise was simulated which overcame those limitations. Introduction The Bu Hasa Field onshore Abu Dhabi is a super giant carbonate oil field. The Lower Cretaceous Shuaiba member of the Thamama formation is the main reservoir with porosity above 30%. This field has been producing since 1963 and production mechanism is involving peripheral water injection and crestal gas and water injection. (Figure 1) The monitoring of this field is essential to optimize the production parameters and the value of using seismic information (4D) as an additional reservoir monitoring tool has been assessed [2]. Although seismic is not always considered as fit for purpose for limestone reservoir monitoring because of the stiffness of the rocks Bu Hasa field is a favourable case because of the high porosities encountered. (up to 30%) Bu-Hasa oil is light and very compressive; therefore the mechanical behaviour of the oil is closer to gas than water. This means injected water front movements should be more easily detected than injected gas front (in the oil).SHELLSPE108207Surveillance4D SeismicNew TechniquesNew 4D Seismic Monitoring Techniques As Enablers For Effective Smart FieldsRodney Calvert and Andrey Bakulin, Shell Intl. E&P Inc.Abstract New 4D seismic methods have been developed that can greatly improve the sensitivity speed and economy of more continuous monitoring for field control. They will increase the range of fields that can be monitored and benefit from enhanced recovery. The need for 4D seismic monitoring The obvious aim for managing a modern oil field is to be able to maximize return by optimizing control of production. This requires a continuously accurate status of the field a means of predicting the outcome of various intervention actions such as new wells flow control settings or Enhanced Oil Recovery (EOR) techniques choosing the best outcome and having a means for implementation. The technical enablers for this strategy are accurate status monitoring in space and time (4D) and a realistic model for simulating performance outcomes. It turns out that adequate forecasting models may only be achieved by production and 4D monitoring measurements much like weather forecasting. This should not be a surprise. Fluid flow depends upon pore scale properties such as permeability and wettability. While porosity may vary a few percent in a reservoir permeability may vary by orders of magnitude between tight barriers and permeable paths along fractures. It is these outliers of permeability that often control performance. We have no reliable way of predicting permeability away from wells. Interpolating the odd core plug measurement is wholly inadequate (Fig 1). Depositional reservoir sequences can be highly heterogeneous even before faulting and diagenesis. Preproduction simulation models have a near zero probability of being adequate for good field prediction and control. Using status predictions from these models as a substitute for actual status measurement will lead to sub-optimal performance and typically low recovery factors. Updating models history matching to production data is still highly ambiguous as it lacks status information away from the wells nearly all the field. The only way to determine the flow performance of a reservoir is to flow it and carefully monitor what happens in space and time. 4D seismic is a key technology for this. With 4D monitoring we can track fluid saturation changes and certain pressure and compaction changes in space. This gives much more constraint on possible models yielding much better forecasts. These models however are still not perfect as accurate permeability models require tracking saturation or pressure changes throughout the reservoir. We call a field with an adequate monitoring program periodic model update and forecasting and active flow control optimization a Smart Field. The requirements and benefits of good 4D The key to effective 4D seismic monitoring is to perform closely repeatable measurements and be able to measure small production related changes. The more repeatable our measurements and the smaller the changes we can monitor the earlier we can see deviations from our predictions update our models and take corrective action. The 4D seismic technique has some surprising natural advantages that dramatically improve its performance and ease of interpretation. Although we think of seismic data as noisy it turns out that most of the noise can with care be repeated and differenced away. Most of the shorter wavelength noise is due to scattering from ubiquitous subsurface heterogeneities. If we closely repeat the shot receiver ray paths we will repeat the scattering response and may difference it away. How closely should we repeat these ray path geometries? The closer the better but typically within 50m for deep water within 10m for 100m water and within 1m onshore. With care even multiples may be repeated and differenced away. In the marine case surface multiples will become seriously non repeatable if there are tide or water velocity change differences between surveys. This either requires effective multiple suppression for each survey or application of our proprietary technique for subtracting away surface multiple differences.1OnePetroBPSPE108435SurveillanceAbandoned wellUncertainty ManagementClair Field: Reducing Uncertainty in Reservoir Connectivity During Reservoir AppraisalA First-Time Application of a New Wireless Pressure-Monitoring Technology in an Abandoned Subsea Appraisal WellB.P. Champion, SPE, Expro, and I.R. Searle and R.K. Pollard, BPAbstract Reservoir connectivity is a key uncertainty when considering field appraisal and development options. Reducing this uncertainty can provide significant benefits in optimising the field development plan. Through the application of new wireless telemetry technology (Expro CaTSTM) a fully abandoned subsea appraisal well has been cost effectively converted into a valuable reservoir monitoring asset. Clair Ridge appraisal well 206/8-13Y was drilled in 2006 and located some 8km from the existing Clair production platform. The well was the first step in an appraisal programme designed to confirm the next stage of development of the Clair Field. Reservoir connectivity and the risk of compartmentalisation are key uncertainties for development of the Clair reservoir (ref.1). On completion of testing operations the well would typically have been permanently abandoned and of no further value for reservoir monitoring purposes. By installing a battery powered wireless pressure monitoring system in the well at the time of final abandonment it was possible to monitor for any fluctuations in the reservoir pressure in the Clair Ridge resulting from production / injection events on the Clair platform. This newly emerging wireless telemetry technology transmits data from the reservoir to the seabed using the well casing as the communication path and advantageously the signal is not attenuated by the presence of cement or bridge plugs in the wellbore. The reservoir pressure and temperature data that is transmitted up the casing is collected and stored by a CaTS subsea receiver located on the seabed. The stored data can be recovered on demand by a supply vessel located overhead using well established through seawater acoustic communications. The use of a wireless gauge enabled a downhole well abandonment to be performed. The traditional method for converting subsea appraisal wells for pressure monitoring has utilised a gauge and cable system (ref.2). This approach requires a relatively complex and costly semisub rig workover for final well abandonment. With the CaTS system the well can be left fully abandoned downhole to UKOOA category 1 at the end of appraisal drilling. The remaining abandonment liability is just for recovery of the seabed receiver and final severance of the wellhead using a diving support vessel. This paper demonstrates that advances in wireless telemetry technology now enables critical reservoir data to be obtained from suspended/abandoned subsea wells or zones where previously there was no cost effective means to do so. By monitoring the reservoir pressure variations in the abandoned Clair Ridge appraisal well clear evidence of reservoir connectivity to the existing Clair platform reservoir area was demonstrated. This world first successful application of new wireless telemetry technology in a UKOOA category 1 subsea abandoned well marks a milestone achievement in advancing technologies that can cost effectively reduce uncertainty in reservoir connectivity at the field appraisal and development stages. Introduction The Clair field was discovered in 1977 and is estimated to have >4 billion bbl overall STOIIP making it one of the largest discovered hydrocarbon resources on the UKCS. The field is located 75 km west of Shetland in water depths of up to 140 m and extends over an area of approximately 220 km2. Composed of fractured sandstones of Devonian age it is the largest naturally fractured reservoir developed in the UK. Production from Clair began in February 2005 through the Phase 1 platform. This is a waterflood development specifically targeting reserves in the Core Graben and Horst segments in the southern part of the overall Clair reservoir. The undeveloped field area is expected to hold considerable further reserves but it is relatively un-appraised. The structurally elevated Ridge segments were identified as potentially the most prospective and a multi-well appraisal programme was developed. This programme also included extension of the original ocean bottom cable (OBC) seismic survey that was shot for development of the Phase 1 area.SCHLUMBERGERSPE101140SurveillanceBy-passed Oil DetectionMature FieldsPractical Steps for Successful Identification and Production of Remaining Hydrocarbons Reserves in a Mature Field - Case study From Tinggi, MalaysiaM. Claverie, SPE, Schlumberger; N.A. Malek, SPE, Petronas Carigali; and K.F. Goh, SPE, SchlumbergerAbstract After more than 20 years of exploitation many of the thick and prolific reservoirs of the Malay basin are depleted. However field studies indicate that large volumes of hydrocarbons remain located in lower quality but producible layers. These reserves are the focus of monitoring and recompletion campaigns to maintain production and extend field life. Most wells intercept thick accumulations of multi-layered reservoirs which are produced from dual tubing strings multiple packers and selectable sliding side doors. In these difficult conditions special care must be brought to the planning acquisition and interpretation of monitoring surveys and to the execution of re-perforation water shut-off and other recompletion solutions. This presentation highlights the practical steps that have led to a successful campaign of identification and production of remaining reserves in the Tinggi field offshore Peninsular Malaysia. Introduction Through-tubing tools record pulsed neutron Gamma Ray (GR) decay-rate for Sigma log GR spectroscopy for Carbon-Oxygen log and oxygen activation for water velocity log (Fig. 1; Ref. 1 2 3 4). Formation waters are fresh (15 000 ppm NaCl equivalent) and Sigma log does not allow differentiation of formation oil from water due to their similar capture cross-section: Sigma oil equals 21 capture units (cu) and Sigma water equals 26 cu. However the Sigma log is well suited for gas evaluation because Sigma gas equals approximately 6 cu. Instead Carbon-Oxygen (CO) logging which is independent of water salinity is the preferred method of saturation monitoring. The CO log can be recorded in casing below the tubing shoe - or inside single or dual tubing sections. The CO log is sensitive to the effect of completion items and borehole fluids. The CO response to formation rock and fluids is well characterized in single casing conditions but logging within single and dual tubing is more complex because of the extra tool to formation stand-off and the increased effect of borehole fluids and tubing steel. Cased-hole resistivity can be an alternative to CO logging but can only be run in single casing. Logging the reservoirs located across the tubing strings would therefore require the dual-tubing to be pulled out. The recently introduced through-tubing version of the tool is suitable for casings up to 7 inch outer diameter where most completion casing diameters in Tinggi are 9-5/8 inch. Tinggi a classical Malay Basin oilfield Tinggi field is part of the PM-9 block located in the southeastern part of the Malay Basin approximately 280 km offshore east of Kerteh Malaysia (Fig. 2; Ref. 5 6). The field was first discovered in July 1980 and developed between 1982 and 1984. After production of more than 20 years the field is at its tail-end of production with more than 97% of its Estimated Ultimate Recovery (EUR) produced. Continuing efforts must be made to ensure production sustenance for such a mature field and as such identification of remaining hydrocarbons is vital before any abandonment process is even considered. The Tinggi structure is a small east-west trending anticline with early Miocene age sandstone accumulation in a shallow marine environment. The field consists of stacked reservoirs with a large aquifer that provides a strong bottom water drive. The reservoirs are produced under a combination of natural water drive and gas re-injection at the crest of the gas cap to obtain closure of both the OWC and GOC at the perforations. (Fig. 3) As part of the Tinggi teams effort to find opportunities for additional production in the field the openhole logs of all the wells were reviewed to identify previously overlooked zones that might still containing hydrocarbons. However as the openhole logs were taken more than two decades ago the team needed to ascertain the current saturation of fluids in the reservoir before any further work could be done. CO logging was chosen as the preferred method of data acquisition for reasons explained in the previous section.OnePetroSHELLSPE109077SurveillanceBy-passed Oil DetectionMature FieldsIdentification of Bypassed Oil for Development In Mature Water-Drive ReservoirsTan Teck Choon, SPE, Sarawak Shell BerhadAbstract An integrated bypassed oil identification methodology was developed and successfully applied to identify and quantify the presence of bypassed oil opportunities in mature water-drive reservoirs in an offshore field in Malaysia. A 3D reservoir static model was first built as part of the geological review. Reservoir performance review was carried out in conjunction with material balance and average fluid contact movement calculations to understand the drive mechanism and to estimate the current fluid contacts. Performance matching was carried out with an analytical 1D 2-phase Buckley-Leverett model to assess the potential scope of recovery with additional development. Together with dynamic production data animation on 2D maps a good view of the production-drainagewater influx pattern progression with time was obtained enabling a first pass identification of bypassed oil opportunities. Well performance data were then used to estimate the likely local fluid contacts in the area or sand layers of the completions. The inferred fluid contacts defining the identified bypassed oil were further calibrated with fluid contacts seen in recent wells and crosschecked with 3D seismic features where possible. Bypassed oil-in-place volumes were calculated using the saturation-initialized 3D static model. The methodology had been successfully applied in reviewing 14 highly matured water-drive oil reservoirs with small to large initial gas caps. The emphasis of this paper is to describe how it can be applied to locate bypassed oil. Although the field concerned had undergone 8 previous phases of development campaigns application of the approach had led to identification of a substantial number of potential recovery opportunities for further development consideration. The approach can be applied for systematic identification of bypassed oil opportunities in water-drive reservoirs where detailed dynamic simulation is not justified. It furnishes a comparatively quick fit-for-purpose approach to identify further development opportunities and furnish input for the planning of detail dynamic simulation where the remaining opportunities scope is large. Introduction The objective is to identify the location of bypassed oil development opportunities in and to estimate the potential recovery scope without resorting to detailed dynamic simulation. In the field studied full dynamic simulation was considered too resource intensive in view of the large number of reservoirs involved long production history and potentially low remaining reward as the cumulative recovery efficiency attained has exceeded over 90% of technical ultimate recovery. The results of bypassed oil identification however may lead to recommendation for full dynamic modeling where the scope is substantial and risks are considered too high without simulation. Most previously published bypassed oil identification techniques relied mainly on a combination of reservoir characterization and observation of oil in open hole or through casing logs. This paper described a systematic approach which integrates analysis and inferences from a few techniques to locate bypassed oil in mature water drive reservoirs. They comprise conclusions drawn from average reservoir fluid contact movement calculations calibration with logged contacts estimation of local area contacts from performance and animation of production data to locate bypassed oil. The robustness of the approach lies in the integration and use of collaborative evidences from different techniques to come to a conclusion on the location and extent of bypassed oil even in difficult cases where petrophysical fluid interpretation is ambiguous. The deduction from any single method is insufficient.SCHLUMBERGERSPE114027SurveillanceBy-passed Oil DetectionPulse Neutron LogsThe Use of Pulsed Neutron Measurements for Determination of Bypassed Pay: A Multi-Well StudyJeffrey Grant, Dale May and Keith Pinto, SchlumbergerAbstract Pulsed neutron measurements have been used since the early 1960s to measure porosity and sigma through casing. Since the formation sigma response is proportional to the salinity of the formation water pulsed neutron measurements are used to determine porosity and water saturation behind pipe. In parts of west Texas and southern California it is common to use through-casing pulsed neutron measurements for water and CO2 flood monitoring. By comparing time-lapse pulse neutron data it is possible to determine changes over time in water gas and oil saturations. The concepts and methodologies that allow time lapsed pulsed neutron measurements to be used for water and CO2 flood monitoring can be used to identify bypassed pay in fields that have been under only primary production. In water and CO2 floods the base pulsed neutron measurement is compared over time with subsequent pulsed neutron measurements. The changes in the pulsed neutron porosity and sigma measurements are related to changes in oil gas and water saturations. Most producing wells do not have base pulsed neutron measurements. Many of these wells do have porosity and resistivity measurements that were acquired prior to setting casing. There are many challenges faced when attempting to incorporate various pulsed neutron measurements with the original porosity and resistivity measurements for a consistent evaluation. This paper will present the methodology of incorporating the present day pulsed neutron measurements with the original porosity and resistivity measurements into a comprehensive petrophysical model. This model will solve simultaneously for the original hydrocarbon in place along with the current hydrocarbon in place. This paper will show how the combination of pulsed neutron measurements and original open hole log data on a multi-well basis was used to identify bypassed hydrocarbons. The bypassed pay was used to design a recompletion program and resulted in significant increases in both produced hydrocarbon and proven reserves of hydrocarbon. Based on the increase of hydrocarbons found by bypassed pay analysis a re-completion program was designed and put into action that resulted in an increase of produced hydrocarbons and proven reserves of hydrocarbons.OnePetroOnePetroSCHLUMBERGERSPE117963SurveillanceBy-passed Oil DetectionUsing the Optimal Through-Casing Measurement to Maximize Oil Recovery: A Case Study From The Western Desert, EgyptM. Van Steene, SPE, B. Herold, SPE, D. J. Dutta, SPE, Y. Abugren, S. Hosny, Schlumberger, A. B. Badr, SPE, I. Mahgoub, SPE, A. Zidan, Agiba Petroleum CompanyAbstract Accurate time-lapse saturation information is the key to making the right decisions on completion strategy maximizing oil recovery and reducing water cut. This paper presents a case study from the Bahariya Formation a heterogeneous fluvio-marine channel deposit in the Western Desert Egypt. All the wells considered in this paper showed significant water production. To identify the main water-producing zones and the bypassed oil all the wells were logged using a through-casing formation resistivity tool. One well was also surveyed with pulsed neutron capture logs. Based on the log results depleted zones were identified and the intervals contributing most to the water production were isolated. Water cut was significantly reduced. In some wells the saturation analysis revealed that the stacked reservoir zones had variable levels of depletion and that the depletion was not necessarily related to the distance to the original oil-water contact. In these wells the water shutoff leaves oil behind and a different completion strategy was recommended. The results from the resistivity and nuclear measurements are discussed in detail with respect to environmental effects. This case study demonstrates that through-casing formation resistivity measurements provide more robust answers compared to neutron measurements in the studied environment. The deeper depth of investigation is extremely valuable as the wells cannot be logged under dynamic conditions and fluid reinvasion is always present. Moreover in view of increasingly high rig rates and limited rig availability the simple nature of the processing and interpretation of the through-casing formation resistivity log enables fast decisions. These examples from the Western Desert illustrate how analysis behind casing provides critical information to maximize oil production and facilitate water shutoff decisions. Introduction The field studied in this paper is located in the Western Desert of Egypt. It has been producing oil since 1992 from the Bahariya Formation a heterogeneous fluvio-marine channel deposit. In 2006 the oil production started to decline with a sharp increase in water cut. Four wells were selected by the operator for water shutoff operations. In each of these the water cut was more than 70%. In each well through-casing resistivity was acquired. A pulsed neutron capture (PNC) tool was run in one of the wells. On the basis of this data immediately after the resistivity run a decision was made about which zones had the highest water saturation and needed to be isolated. This was done by setting a bridge plug. The same rig was used for the logging and the setting of the bridge plug. The water shutoff operations successfully increased the oil production. The purpose of this paper is to demonstrate the potential of the through-casing resistivity measurement compared to its nuclear counterpart since its deep depth of investigation gives more immunity to reinvasion. The interpretation is fast and hence allows making an almost real-time decision on water shutoff operation so that it can take place immediately after logging. Saturation Measurements Behind Casing Three main types of data are used in saturation monitoring: through-casing resistivity pulsed neutron capture and neutron inelastic capture measurements. Aulia et al. (2001) provide a comparison of the applicability of each measurement in different environmental conditions.SHELLSPE109007SurveillanceCO2 DetectionTemperature LoggingThermal Signature of Free-Phase CO2 in Porous Rocks: Detectability of CO2 by Temperature LoggingS. Hurter, SPE, Shell; A. Garnett, PTC Consulting; and A. Bielinski and A. Kopp, University of StuttgartAbstract This study examines the suitability of thermal methods especially DTS (Distributed Temperature Sensing) cables (in the annulus or behind casing) to monitor the fate of injected CO2 for emissions reduction purposes. The static temperature signal of CO2 stored in pores of sandstone and claystone examples is calculated as a function of porosity CO2 saturation and CO2-filled reservoir thickness. The dynamic temperature signal associated with the movement of CO2 in the well and the porous rock is discussed and results of numerical simulations are presented. The detectability of these temperature signals is assessed and found to be useful in detecting leakage over short time intervals and saturation changes in the storage reservoir over the longer term. Introduction Non-seismic methods to monitor the injection and long-term fate of CO2 injected into the subsurface for emissions reduction purposes need to be developed. The deployment of temperature sensors in wells (in the annulus or behind casing) may provide a method to assess if injected CO2 remains stationary in the formation or moves slowly after injection has been terminated and wells abandoned. Additionally thermal methods could help to monitor well and caprock integrity over long times. The injection and storage of CO2 in a geological formation changes the subsurface temperature field through various processes: The contrast in thermal properties (e.g. conductivity) between CO2 and brine affects the bulk thermal conductivity of the reservoir rock and therefore of the temperature field compared to that in the absence of CO2 (steady-state scenario). In the case of leakage of CO2 (through faults fractures corroded casings etc.) it will expand as it rises. This could cause cooling close to the leakage point and during phase change (Joule-Thompson) a dynamic scenario. There are also thermal effects simply related to initial injection temperature being different from the surrounding formation temperature. Measuring and recording the temperature over time provides insights into the occurrence and magnitude of these processes. Two types of temperature signals are of interest for monitoring CO2 sequestration in the subsurface. A static or quasi-static temperature signal related to presence or absence of CO2 i.e. changes of the thermal properties of the rocks due to the presence of CO2 in their pores and fractures. The second type of signal is a dynamic thermal effect related to the movement of CO2. Here the temperaturOnePetroOnePetroHeriot Watt UniversitySPE102867SurveillanceComplex WellsValue of InformationData Richness and Reliability in Smart-Field Management - Is There Value?G.H. Aggrey and D.R. Davies, Heriot-Watt U., and A. Ajayi and M. Konopczynski, WellDynamics Inc.Abstract An essential part of the process to determine the value of advanced wells and fields is the explicit inclusion of the reliability of the various measurement sensors in particular and the data collection transmission and analysis in general when building the Value Statement to justify installation of intelligent wells. The desire for increased intelligence in the monitoring and control systems associated with Intelligent Well Technology (IWT) results in the deployment of more sophisticated and potentially accurate downhole components of greater capabilities. However these results in a more complex completion which can be expected to exhibit a lower reliability than that shown by simpler system. Ultimately the greater number of more complex components may reduce the equipment reliability to such an extent that the increased chance of failure has reduced the Value of Information below that which can be derived from a simpler system. This paper uses a synthetic reservoir to explore and compare the value of extensive accurate measurements with a higher chance of component or system failure (the rich data case) with the deployment of fewer and or lower resolution sensors of greater reliability (the poor data case). The value associated with these two cases will be quantitatively compared in terms of a Risked Opportunity Loss. This comparison will illustrate how this workflow can be used to design cost-effective well completions capable of Real Time Reservoir Management of an Oil or Gas field. The example chosen will also illustrate some of the drivers behind the choice of the optimum completion equipment. 1. Introduction Reservoir management with its tasks of monitoring surface and subsurface data in order to control the movement of fluid in the reservoir so that the reserves are maximized and the production risks reduced has become a critical activity as oil companies strive to minimise costs maximise profitability and sustain long term production. The use of intelligent well completions is a key tool in this activity as it offers a combination of zonal productivity control well performance monitoring and well production optimisation through the ability to remotely reconfigure the completion design without the need for the recompletion intervention required by a conventional well. Intelligent Well Technology (IWT) has developed out of the need to provide the capability for remote reservoir and well monitoring and management. Intelligent-well completions contain appropriate monitoring sensors located along the wellbore. This has frequently been subdivided and segregated into a series of separate production zones by packers located at carefully chosen intervals. The down-hole monitoring sensors and the control and communication systems are linked to form the data acquisition systems (Figure 1). Interval Control Valves (ICVs) control the flow into or out of each of these production zones. IWT aims to maximize reservoir efficiency by increasing production and increasing the ultimate recovery. It may also reduce (possibly) the CAPital EXpenditure (CAPEX) necessary to exploit an asset. However even in cases when CAPEX increases the sum of the CAPEX and the OPerating EXpenditure (OPEX) will reduce due to the completions builtin ability to quickly react to unforeseen events during the production of the reservoir without the need for a (high cost) conventional well intervention. Thus operational risks such as those caused by unsuspected reservoir heterogeneity may be easily and rapidly managed. IWT enabled completions are built with systems capable of downhole data collection and transmission; providing the basic infrastructure for a Real Time Optimization (RTO) capability. Dedicated software has been developed to analyze the completion production and reservoir data measured and transmitted by the RTO system.1 Zonal control algorithms optimize the production process by selecting the appropriate choke setting for the ICV.OnePetroSCHLUMBERGERSPE107119SurveillanceComplex WellsDownhole FlowratesPermanent Real-Time Downhole Flowrate Measurements in Multilateral Wells Improve Reservoir Monitoring and ControlM. Zakharov, Schlumberger; S.H. Eriksen, Hydro Oil & Energy; and I. Raw, S. Pride, andA.Ridez, SchlumbergerAbstract During the last decade intelligent well completions have evolved to become engineered solutions widely used for both monobore and multilateral horizontal wells. However a clear understanding of zonal or lateral branch flow contributions still remains an issue. Several SPE papers covering the issue have been published recently. This paper presents the engineered solution for a TAML level 5 dual-lateral horizontal well that was drilled and completed in the Oseberg Sr field in December 2005. The solution combines hydraulic flow control valves with advanced downhole two-phase flow and density measurement provided by a Venturi-based flowmeter with a gamma ray source and detector. Real-time data were used to optimize the settings of the downhole chokes to obtain a balanced production from the two horizontal wellbores. The completion provides the capability to control and measure in real time flow contributions from both laterals and is the first installation of its type. This capability is critical for production and reservoir optimization. Additional value of the technology is demonstrated by the analysis of acquired downhole data. Productivity Indices are obtained for each of the two laterals without any production loss associated with shutting down the other lateral branch. Data analysis indicated a decrease of the Productivity Index for one of the two horizontal wellbores. The successful installation of the two-phase flowmeter in an intelligent completion is a significant milestone corresponding to the general trend in the industry to improve inflow control and the understanding of flow contributions in multilateral wells. This solution for flow control and measurement can be applied effectively in both multilateral wells and monobore wells designed for commingled production from different reservoirs where accurate production allocation is a critical issue. Introduction Intelligent completions have developed over recent years with increasing functionality to meet specific applications. Norsk Hydro has been particularly active in implementing innovative intelligent completion solutions to meet its objectives.1 This implementation commenced in 1998 with natural gas lift on the Troll field using hydraulic gas lift valves. For the Fram Vest field an innovative natural gas lift completion was implemented using this field proven technology repackaged for a more efficient safe and environmentally friendly completion system. Several intelligent wells were completed on the Oseberg field with long reach highly deviated wells having flow control of two to three zones with hydraulic flow control valves. Norsk Hydro then turned its attention to flow control of multilateral wells. A completion solution integrating flow control of the lateral and main bores together with natural gas lift was implemented on the Troll and Vestflanken subsea fields. There was a growing understanding that downhole production monitoring was needed in order to draw the full benefit of the intelligent multilateral completions. This resulted in the installation of Schlumberger downhole flowmeter in Norsk Hydro multilateral well F-29 on the Oseberg Sr field. The well was completed with flow control of both the main bore and lateral bore with flow measurement of the main bore. Applied downhole two-phase flow and density measurement principles were the same as for BP Harding well PN1.2 Oseberg Sr Field Description The Oseberg Sr field operated by Norsk Hydro is situated 130 km west of the Norwegian coast. The main oil-producing reservoir is the Tarbert formation within the Brent group which is of variable reservoir quality with permeabilities ranging from 1 D to 1 mD. The 33 API oil was initially slightly under-saturated but some parts of the field have been heavily depleted. The field comprises several structures that are drained by extended reach and horizontal oil production wells. The development includes both platform wells and two subsea templates that are tied back to the platform. Reservoir pressure is supported by water and gas injection.SCHLUMBERGERSPE100992SurveillanceComplex WellsInflow ProfilingA Novel Solution to Flow Profiling With an Improved Production-Logging Tool In Short String Section of Dual String CompletionsKoksal Cig and Ihsan Gok, SchlumbergerAbstract The new production logging tool string and interpretation technique were established in order to solve the surveillance limitations in the short string section of the dual completion wells. The logging program was initiated in Kuwait Sabriyah Field where there are two major producing formations: Mauddud Carbonate and Burgan Sandstone Formations. The wells were completed with dual production strings due to distinct fluid and reservoir properties in these formations. Water injection was implemented in Mauddud Formation in late 2000 after a successful waterflood pilot program. The wells having water injection are mostly located in the short string section of the dual completions. The monitoring of the water breakthroughs and finding the bypassed oil became crucial for the field development. Understanding of the reservoir required logging these sections. The conventional wireline logging was regarded as a difficult and unsafe operation due to complicated nature of the production strings and the risk of wireline logging tool entangling. The earlier practice was to utilize the workover rig and to remove the two production strings before performing any wireline logging in the well. This operation was not only costly and time consuming but also pausing the production from Burgan Formation. The new logging string and interpretation technique were developed to survey the short string section of the dual string completions without utilizing a rig. The logging operation consisted of conveying the production logging tool with a coiled tubing through the short string section of the dual completions. Flow profiles and water entries were confidently obtained in many wells with the new interpretation technique. This paper presents the history of the short string logging operations in the North Kuwait Fields and highlights the improved coiled tubing conveyed logging tool string and the recent interpretation technique in order to overcome the problems due to completion restrictions. Introduction The improved production logging tool string was utilized in the Mauddud Formation in order to identify the flow profile mainly to locate the water entry intervals. Mauddud Carbonate Formation in the North Kuwait is consisted of two large anticlines named as Sabriyah and Raudhatain Fields. Mauddud Carbonate Formation is located below Tuba Carbonate and above Lower and Upper Burgan Sandstone Formations. These formations are independent from each other and separated with clear petrophysical signatures. Mauddud Formation containing no natural pressure support has a production history of more than 40 years. The depletion drive mechanism causes the swift pressure decline in the field. Studies indicated that water flood with artificial lift would significantly improve the oil recovery in the Mauddud Formation. The focus in this article is the production logging applications in the Sabriyah Field. The following part summarizes the reservoir properties and production history of the field. Sabriyah Field has oil gravity ranging 18-26 API GOR varying 60-350 scf/bbl porosity of 18-22% permeability of 15-60 md bubble point pressure of 300-1900 psia and oil viscosity at the bubble point ranging 2.5-15 cp. Uncertainties of the fluid type were eliminated with the extensive zonal sampling in the field. The PVT data illustrates that the oil has higher viscosities with the increasing depth hence showing the oil quality deterioration1. Figure 1 shows typical well logs in Mauddud Formation in Sabriyah Field. The seawater injection water flood program was designed to reduce the pressure depletion and increase the sweep efficiency. After successful water injection pilot project in Sabriyah Field the water flood project was initiated with 12 inverted nine spot patterns having 250 acre spacing for each well at the crestal part of the reservoir in November 2000. Since the commencing of the waterflood more than 100 million bbls of treated seawater was injected from 12 injectors in about 50 km2 area.SCHLUMBERGERSPE103589SurveillanceComplex WellsPLTPushing the Envelope for Production Logging in Extended Reach Horizontal Wells in Chayvo Field, Sakhalin, Russia New Conveyance and Flow Profiling ApproachD.E. Fitz, ExxonMobil Upstream Research Co.; Angel Guzmn-Garcia, ExxonMobil Exploration Co.; and Ram Sunder, Matt Billingham, and Vitaly Smolensky, SchlumbergerAbstract Production logging and flow profile interpretations are necessary to properly assess completion performance and interpret pressure buildup data in Chayvo Field. With a lateral reach in excess of 8 km acquiring production logging data is difficult. Memory logging with conventional production logging tools via coiled tubing and a hydraulic tractor was employed. However due to the wear experienced by the coil high cost and poor data quality at low flow rates this technique was abandoned after initial logging efforts. Development of a state-of-the-art electrically powered tractor combined with new surface read out array mini-spinners and optical gas and array resistivity water holdup sensors provided a viable logging alternative with a 40 000 ft cable specifically manufactured to avoid splice induced weakness. This new logging technology detects and measures stratified flow and lower flow rate fluid entry than conventional axial symmetric production logging tools in ERD well bores. The equipment has recorded production logs to a measured depth of 9 775 m at a true vertical depth of 2 613 m. Comparison of cumulative flow rates from the array mini-spinner analysis to the logging-while-drilling derived cumulative permeability-thickness product has enabled the evaluation of the completion methodology. Based on the production log analysis the new completion methodology appears to have restricted flow from the higher permeability intervals while permitting flow from lower permeability intervals. The methods used to plan and execute these production logging programs and the integration of the interpretations into the pressure-transient analysis for the complex completions of multi-layered reservoirs are discussed. Examples illustrating data quality and interpretation are provided. Introduction Chayvo wells have long sail sections at angles greater than 70 over several kilometers followed by a horizontal section of 1-3 kilometers extent. These wells intersect multiple reservoirs at low dip angle that are produced with a single commingled completion and well test interpretation requires accurate estimation of the relative flow rates from each producing reservoir. Conventional wireline logging is not possible because of the high-hole angle and the long reach. Wireline logging using typical tractors is not practical either because they do not provide enough tractive force to reach the toe of the well. Conventional coiled tubing conveyed logging was also not practical because of the friction produced in the long-reach wells. This left two possibilities: coiled tubing conveyance with a hydraulically powered tractor or wireline logging with a new much more powerful tractor. Examples using both types of conveyance are given here. Production log interpretation in horizontal wells is complicated particularly with two-phase (gas-oil) flow down-hole as in Chayvo. Interpretation with a conventional turbine spinner or a full-bore spinner becomes inaccurate in these cases causing reliance on the temperature log which is also difficult to interpret since the geothermal gradient is essentially zero in a horizontal well. Interpretation gets more difficult once water breakthrough occurs. Array holdup tools of capacitance optical and resistance type have been available for some time [2 4]. Recently an array mini-spinner has been introduced that has proven quite useful in better characterizing stratified flow in high-angle wells [5]. General Well Description The main oil productive reservoirs in Chayvo lie 8-9 km offshore from the drilling rig location at depths of 2400-2900 m TVDSS (see Figure 1). Reaching these reservoirs requires a short vertical shallow section building to a sail angle of 70-75 to reach the landing depth of the 12-1/4 hole that is in the shale that seals the primary reservoir. The well is then drilled horizontally into the primary and secondary reservoirs at a depth that is approximately midway between the GOC and OWC.SHELLSPE112204SurveillanceComplex WellsProduction ProfilingProduction Surveillance and Optimisation for Multizone Smart Wells With Data Driven ModelsK.C. Goh, Shell Global Solutions International B.V.; B. Dale-Pine and I. Yong, Brunei Shell Petroleum Company Sdn. Bhd.; and P. Van Overschee and C. Lauwerys, IPCOS N.V.Abstract The Champion West field was discovered in 1975 offshore Brunei but its oil reserves in a complex web of thin reservoirs were initially deemed too expensive to develop. Field development was slow due to reservoir complexity and technology limitations. The current phase of development of the Champion West reservoirs uses long horizontal snake wells which create multiple drainage points in sands effectively achieving a similar drainage pattern of several conventional wells. The snake wells intersect up to 4 kilometers of reservoir intervals with total depth of up to 8 kilometers and are divided into several zones with external casing packers or swellable packers. Each zone is then equipped with an inflow control valve and pressure and temperature sensors to allow monitoring and optimization of the recovery process from that zone. Historically for long horizontal wells the effective control of production profile and effective tracking of production from individual zones have been problematic. Poor tracking of production will adversely impact overall management and ultimate recovery from a reservoir. One solution is to fully utilize surface and downhole pressure data and multirate well tests to generate data driven models to determine zonal inflow zonal interactions and flow across inflow control valves and to compute ICV settings for optimum reservoir management. FieldWare Production Universe (FW PU) is a software application developed by Shell International Exploration & Production and Shell Global Solutions International with significant involvement and support from Brunei Shell Petroleum Company Sendirian Berhad(BSP) for robust data driven modelling in an production operations setting that provides continuous real time estimates of well-by-well production. Applied to the Champion West multizonal wells the FieldWare PU models built using surface and downhole test data and an understanding of well performance provides regularly validated estimates of zonal production rates using real time surface and downhole data. Using this tool inflow control valve settings are suggested to the user in order to optimize production on a daily basis through the use of mathematical optimization routines taking into account all available data. The system also provides early warning to the field management team of any wells deviating from well reservoir management guidelines. The intent of this technology is to enable more transparent sustainable and systematic management of smart well production systems through the use of real time data to improve the understanding of reservoir behaviour and to allow early intervention to optimize production and ultimate recovery.SCHLUMBERGERSPE105362SurveillanceCondensate Banking DetectionMultiphase FlowmetersThe Identification of Condensate Banking With Multiphase FlowmetersA Case StudyB.C. Theuveny, P.D. Maizeret, N.S. Hopman, and S. Perez, Schlumberger Oilfield ServicesAbstract The identification of condensate banking has always been a challenge. Furthermore large productivity losses can result from the absence of early detection of a condensate bank in the near well bore area of the well. The traditional means of detecting a condensate bank range from comparison of the dew point to downhole pressure measurements identification of composite radial models and quantification of skin using pressure transient analysis. One of the methodologies that have been more theoretical than practical has been the detection of a leaner stream of effluent at the well head during production. This type of approach has been quite challenging in the past as a high resolution measurement of the condensate to gas ratio is essential to a successful diagnostics of condensate banking. The paper presents a case of analysis of the development of a condensate bank during a well test. The multiphase flowmeter identified a gradual reduction of the condensate to gas ratio with increasing choke sizes. The methodology of diagnostics is demonstrated in particular with the discrimination against liquid loading issues. The PVT compositional analysis provides a verification of the analysis and the observation of the evolution of the phase diagram leads a further understanding the downhole and near well bore thermodynamic phenomena. The degradation of the productivity of the well is also analyzed with a significant drop of gas productivity observed even on smaller choke sizes at the end of the test. Finally the paper presents a numerical simulation match of the data and provides a number of recommendations for the utilization of single well - near well bore compositional models to help interpreter to obtain better and simpler matches. This paper provides a new methodology to make full use of the benefits of the dual energy gamma Venturi multiphase flowmeters in the evaluation of gas wells. Operational issues related to gas well testing with traditional test separators The test of gas wells has always been a challenge compared to testing oil wells. The high level of energy contained in the stream in the form of compressible fluids the higher pressure usually encountered at surface due to the lower hydrostatic head in the tubing and the potential presence of toxic components such as H2S in the effluent contribute to increase the Health and Safety risks inherent in the handling of gas wells. On the operational side the presence of water in the stream combined with a large temperature drop across restriction or the choke can lead to severe plugging issues with hydrates. Erosion can also be a serious risk encountered with the combination of high fluid velocities (in particular at low pressure) and a bit of sand. Perforation of the walls of the surface piping can present very serious risk to the operational personnel and the facilities. However the main difficulty of testing gas wells comes from the determination of accurate gas condensate and water flow rate measurements. The short retention time in traditional test separators can lead to significant carry over of condensate in the gas line resulting in an underestimation of the condensate rate and a potentially significant error on the gas rate. The level of error on the gas rate will depend on the type of measurement technology used. If traditional orifice plate is used the presence of condensate in the gas stream leads usually to an overestimate of the gas rate. The error on the gas measurement can also be compounded with the accumulation of well liquids (water or condensate) in the legs of the DP cell around an orifice plate which can create large errors (usually identifiable in the raw data by a near linear trend of drift of the DP measurement). There can also be significant amount of liquid trapped at the bottom of the pipe in front of the orifice plate which also can affect the flow rate measurements. The field identification of such problem can be straight forward but its remediation may be impossible during the course of the well test operation.OnePetroSCHLUMBERGERIPTC12108SurveillanceData AcquisitionChallenging ConditionsImproved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate EnvironmentK.D. CONTREIRAS and F. VAN-DNEM, Sonangol P & P; P. WEINHEBER, A. GISOLF and M. RUEDA, SPE, Schlumberger Oilfield ServicesAbstract The combination of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low double or single-digits saturation pressure is usually within a few hundred psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud. In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive contamination levels that rendered the samples unsuitable for laboratory analysis. Clearly a more flexible solution was required. In this paper we review the learnings from previous attempts in the Pinda. We show the pre-job modeling that was done to predict the required flow rates and the anticipated drawdowns. Ultimately a two-step solution was used. We first ran a high efficiency pretest-only WFT in order to quickly gather formation pressure data and mobility data. This data was then used to design the sampling string which was a combination of an inflatable dual packer with focused probe. We discuss the decision process that governed the choice of pump displacement unit probe and packer. We pay particular attention to the unique pump configurations that were required to effectively manage the drawdowns when using the probe and also to allow sufficient flow rate when using the dual packer. We conclude with a summary of recommendations and lessons learned for sampling in such an environment. Introduction The Pinda formation offshore Angola was laid down in Albian time in the Upper Cretaceous. By this time the separation of African continent from the South American continent was well underway and full marine conditions existed. As a consequence the Pinda was deposited in a shallow marine environment and is rich in carbonates and is frequently highly dolomitized. In such complex reservoirs the acquisition of quality formation tester samples is crucial to the reservoir evaluation. In this paper we wish to discuss learnings from previous attempts in the same area the subsequent recommendations that were made and their implementation. This discussion is informed by the fact that these are low permeability rocks drilled with oil base mud containing oils that are very close to saturation pressure. We therefore have to design our sample acquisition program with the following considerations: Keep sampling pressure above the bubble point so that the acquired sample remains representative. Ensure that OBM contamination levels are low such that samples are of high quality and DFA data is valid. Minimize time on station such that rig costs and the probability of tool sticking are reduced.SCHLUMBERGERSPE115504SurveillanceData AcquisitionChallenging ConditionsImproved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate EnvironmentK.D. Contreiras and F. Van-Duinem, Sonangol P & P; P. Weinheber, A. Gisolf, and M. Rueda, SPE, Schlumberger Oilfield ServicesAbstract The combination of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low double or single-digits saturation pressure is usually within a few hundred psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud. In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive contamination levels that rendered the samples unsuitable for laboratory analysis. Clearly a more flexible solution was required. In this paper we review the learnings from previous attempts in the Pinda. We show the pre-job modeling that was done to predict the required flow rates and the anticipated drawdowns. Ultimately a two-step solution was used. We first ran a high efficiency pretest-only WFT in order to quickly gather formation pressure data and mobility data. This data was then used to design the sampling string which was a combination of an inflatable dual packer with focused probe. We discuss the decision process that governed the choice of pump displacement unit probe and packer. We pay particular attention to the unique pump configurations that were required to effectively manage the drawdowns when using the probe and also to allow sufficient flow rate when using the dual packer. We conclude with a summary of recommendations and lessons learned for sampling in such an environment. Introduction The Pinda formation offshore Angola was laid down in Albian time in the Upper Cretaceous. By this time the separation of African continent from the South American continent was well underway and full marine conditions existed. As a consequence the Pinda was deposited in a shallow marine environment and is rich in carbonates and is frequently highly dolomitized.BPSPE101846SurveillanceData AcquisitionPumping WellsData Acquisition in Pumping WellsMiljenko Cimic, SPE, TNK-BP Management, and Laura Soares, Partex Oil & GasAbstract Calculating of bottomhole flowing and shut-in pressures and bottomhole flowing rates based on fluid level measurements and casing head pressures was combined with a convolution method of the build-up interpretation for vertical and horizontal wells. The downhole pressures and rates were calculated using a mechanistic model(7) which shows good accuracy after comparing with downhole gauges measured data. The main uncertainty still remains the accuracy of fluid level measurement and water content in the annulus fluid especially during well clean up period which influences the density of the casing fluid column. During the shut-in period conventional pressure build-up analysis (Horner and derivative) and convolution methods were compared with the purpose of showing the advantages of the convolution method over the conventional. Consequently the well test can be more rigorously interpreted by using convolution rate analysis and the shut-in time is reduced by three folds leading to economic advantage of testing costs saving. The real time knowledge of bottomhole pressure and rates can be used to adjust the optimum downhole pump working regime avoiding two phase flow through downhole pump and to perform conventional and convolution methods of interpretation without deploying bottomhole gauges. Majority of brown fields are equipped with different kind of artificial lift system including positive and dynamic displacement pumps. A fluid level measurement combined with a convolution method leads to an improvement of the production and operating economics of different types of artificial lift systems (SR ESP PCP etc.) and can be used as well as a reservoir management tool. This paper includes actual field examples with solutions that can be applied in the completion and testing of pumping wells. A field experience and subsequent achievement with downhole pumps testing in low permeability oil reservoirs are presented in this paper. Introduction Pressure buildup analysis in pumping wells has suffered from the difficulty in directly measuring pressures at the bottom of the well. Often the only reasonable method of acquiring pressure data in such wells is to combine casing pressure and Fluid Level Measurements (FLM) with estimated fluid densities to indirectly estimate the bottomhole pressure which is then analyzed. In such situations the only practical means of gathering pressure data is the use of the FLM method to determine the fluid level in the casing. The Fluid Level Measurement can be used for indirectly computing bottomhole pressure and rate of afterflow in pumping wells. This calculation uses fluid level and casing head pressure data obtained during a transient test. During pressure build-up tests free gas returns back into solution as the pressure increases in the wellbore. This causes a reduction in both oil density and free gas flow rate. A mass transfer(1) between the oil and gas phases occurs in the well annulus during either flowing or build-up conditions. In the paper presented Hasan & Kabir(7) method was used to calculate bottomhole pressure. The bottomhole pressures used in the analyses contain errors due to measurement of the fluid levels and due to uncertainties in the fluid densities. These measurements can easily lead to errors of several percent in the downhole pressure calculations. The fluid level measurement is a direct indication of fluid accumulation in the wellbore (wellbore storage) and gas segregation during a build-up testing when the amount of gas in the fluid column changes. Description of Fluid Level Measurement Methods The Fluid Level Measurement became very important as a well testing technique for pumping wells. Many hydrodynamic models and empirical correlations have been developed to indirectly calculate the bottomhole pressure and the afterflow rate during pressure buildup tests in pumping wells. The use of the Fluid Level Measurement technique to determine bottomhole pressure and bottomhole rate requires an estimate of the gas void fraction in the liquid column of a pumping well annulus. Few correlations relating the annular superficial gas velocity are available for saturated oil columns the most used among them are Godbey and Dimon(4) Podio et al. (5) and Gilbert as reported by Gipson and Swaim(6). The validity of using FLM methods in well testing has been assured because many actual examples have shown good consistency after the downhole pressure was measured as shown in Figure 1. The downhole pressure was calculated by computer program using methodology described below.SCHLUMBERGERSPE126158SurveillanceDownhole MonitoringMultiple ReservoirsAn Innovative Multi-Reservoir Permanent Downhole Monitoring System Through A Single WellAbdullatif Al-Omair, SPE, Orji O. Ukaegbu, SPE, and Muhammed Alshafie, SPE, Saudi Aramco; Muhammad Shafiq, SPE, and Abdullah Almarri, SPE, SchlumbergerAbstract This paper describes an innovative Down Hole Permanent Monitoring System (PDHMS) that allows real-time monitoring of bottom-hole pressure and temperature of two stacked reservoirs using one vertical observation well in a Saudi Aramco field. Permanent monitoring of pressure and temperature enables reservoir engineers to assess the performance of the reservoir in areas such as flood front movement and pressure support maintenance. In this well a multi-reservoir dual gauge system was deployed to monitor pressure and temperature in two stacked carbonate reservoirs. The standard dual-gauge system mandrel architecture requires below packer installation of the gauges which in turn increases the risk of leakage in the electric lines of the system. In this paper we describe an innovative and potentially reliable digital permanent monitoring solution that uses the state-of-the-art welded system that aims to eliminate the risk of leakage. Included in the paper are the design criteria deployment methodology and the lessons learned from installation of this fully welded PDHMS. Introduction Reservoir monitoring is a key tenet for enhancing reservoir performance and extending the ultimate recovery of oil and gas reservoirs. Managing reservoir pressure plays a major role in optimizing the field performance. Saudi Aramcos strategic surveillance program calls for monitoring pressure support and flood front advancement by utilizing permanent downhole monitoring through a network of dedicated key observation wells. The subject field is a carbonate anticline that has been under peripheral water injection since the start up of production. The reservoir is fairly heterogeneous with areal variations in permeability and reservoir architecture. The reservoir was primarily developed with horizontal well completions that intersect varying pressure zones caused by the steepness of the reservoir and the heterogeneous nature of the matrix. In this particular portion of the field an observation well was planned in the area between the injection and the first production line to monitor the flood front efficiency and pressure support advancement. This area of the reservoir is fairly steep and the flood-front has been observed to advance slowly through the reservoir. A dual gauge system was envisioned in an observation well to monitor in real time the change in pressure and pressure gradient as the flood front advances through the wellbore. The changes in fluid gradients will provide an accurate water arrival time that could be utilized in analytical calculations and to enhance reservoir modeling efforts.SCHLUMBERGERSPE93057SurveillanceDownhole PH MeasurementOptical SpectroscopyReal-Time Downhole pH Measurement Using Optical SpectroscopyB. Raghuraman, SPE, and M. O'Keefe, SPE, Schlumberger; K.O. Eriksen, SPE, L.A. Tau, SPE, and O. Vikane, SPE, Statoil; and G. Gustavson and K. Indo, SchlumbergerSummary A new downhole pH sensor has been developed to provide an in-situ pH measurement of formation water at reservoir conditions and results are presented for two wells in the Norwegian Sea. The measurement technique for use with wireline formation-sampling tools uses pH-sensitive dyes that change color according to the pH of the formation water. To make a real-time pH measurement the dye is injected into the formation fluid being pumped through the tool flowline and the relevant visible wavelengths in an optical detector are used to record the dye signal and calculate pH with 0.1-unit accuracy. The pH of a formation fluid alters as the sample is brought to surface from the high-temperature and -pressure conditions downhole owing to acid gases and salts coming out of solution and changes in water-chemistry equilibria. To obtain an accurate pH the measurement must be made downhole at reservoir conditions. Unlike potentiometric methods in which fouling of electrode surfaces by oil and mud is a potential problem the dye technique is robust because the dye is isolated from the formation fluid and is injected into the sample only when a measurement is made. The technique has been applied successfully to both oil-based and water-based drilling muds with successful measurements even in mixed oil/water flows. Multiple measurements of pH at a single sampling station demonstrate that the method is robust and repeatable. These measurements have been compared with numerical simulations using a multiphase chemical-equilibrium model that uses laboratory analysis of collected water samples as input. pH is a key parameter in water chemistry and is critical for corrosion and scale studies. Accurate downhole pH measurement allows a more-accurate selection of appropriate completion materials and more-effective planning for scale treatment and inhibition. Introduction The main objectives of formation-water sampling in exploration wells are to obtain information regarding the scaling and corrosion potential of the water and to establish the salinity of the water for petrophysical evaluation. Formation-water data can also give information about compartments and communication in the reservoir and hence can improve the ability to make the right decisions early in development planning. Later in the production cycle formation-water data can be used to differentiate produced connate water from aquifer- or injection-water breakthrough. Ideally water samples from exploration wells should consist of representative uncontaminated formation water which can be difficult and costly to obtain. The quality of formation-water data is highly dependent on the sampling technique and the type of drilling mud used in the reservoir zone. Oil-based drilling muds will usually provide good-quality water samples because the mud filtrate is not miscible with water. Water-based-mud filtrate can contaminate water samples because the filtrate is miscible with formation water and chemical reactions can alter the true composition. Reservoir water samples are usually collected in open h