bluuebunny/crossref_metadata_2025_split huggingface dataset:
Monitoring of Real-Time Temperature Profiles Across Multizone Reservoirs During Production and Shut-In Periods Using Permanent Fiber-Optic Distributed Temperature Systems
Authors: Fryer V. , Shuxing D. , Otsubo Y. , Brown G. , Guilfoyle P. 
Published: December 2007

Abstract
This paper describes the use of a fiber-optic distributed temperature system (DTS) to monitor and evaluate the production and shut-in thermal profiles in an offshore China well. The objective was to identify and correlate production changes with respect to time over the first phase of a multiphase offshore field development.
The well was drilled from an offshore platform with a deviation of 40 degree across the reservoir section and completed with a 5 inch diameter expandable sand screen (ESS). An electrical submersible pump (ESP) was used to produce the oil. The reservoir consists of multi-layered sand zones and the flow was commingled through the sand screens to the pump intake set in a 9-5/8 inch diameter casing.
The system was commissioned to acquire a better understanding of the flow allocation in the complex stacked reservoir sequence. The importance of this knowledge in the early stages of production is expected to influence future field development.
Continuous distributed temperature monitoring of the well enabled quantitative analysis of the produced fluids to be performed at selected times providing real time, permanent, production monitoring over the reservoir. This technique will allow future wells to be developed with smaller completion sizes by limiting the requirement for production logging "Y" tools.
The data acquired to date has provided improved reservoir characterization and understanding of the dynamics of the reservoir behavior. The data analyzed included initial well unloading and clean-up, zone depletion over time resulting from zone reservoir pressure changes, natural flow on shut-in and differential flow induced from various production rates using a variable speed ESP. These key events would not have been captured with conventional production logging due to normal operating constraints.
As the completions in this field are multi-zone or multi-layer completions, understanding the relative flow contribution of each zone or layer is important for long-term reservoir management. Combined with pressure transient analysis of initial production history, the data collected from the fiber optic DTS has enabled the determination of individual sand lobe flow capacity and a better determination of net pay cut offs. Combined with other open-hole log information, a breakthrough has been achieved for generating accurate models of permeability for each sand sequence within this fluvial deltaic reservoir environment.
The Key to Predicting Emulsion Stability: Solid Content
Authors: Poindexter Michael K. , Chuai Shaokun , Marble Robert A. , Marsh Samuel C. 
Published: December 2007

Abstract
Chemical demulsifiers are routinely added in the oilfield to effectively resolve water-in-crude oil emulsions. As used in the common bottle test, demulsifiers in effect probe or interrogate emulsion stability strength. Emulsion stability in turn is defined by no less than three parameters - water drop, oil dryness and interface quality. All three parameters are direct outputs of the bottle test, and collectively, all three provide a more complete picture of emulsion stability as opposed to the use of any singular parameter.
By selecting a wide variety of demulsifiers and performing a standardized bottle test (as introduced in SPE 84610), emulsion stability from a variety of sites can be quantified and compared. By coupling bottle test results with corresponding crude oil analytical data, fundamental questions concerning factors governing emulsion stability can be quantified. The results show that solid content, not asphaltene content or any other crude oil parameter investigated, is by far the best single predictor for gauging emulsion stability. Furthermore, statistical analysis via partition trees shows that emulsion stability is most aptly described using several input parameters as opposed to a single factor. This statistical technique produces emulsion stability descriptions with Rsquare values on the order of 0.9.
Flow Potential of Fracture Corridors and Mega-Fractures in a Clastic Field in South Oman
Authors: Ozkaya S. I. , Minton K. R. 
Published: December 2007

Abstract
The field is a ‘turtle back' structure bound by a major wrench fault to the north and a salt withdrawl pod to the south. The reservoirs are high net to gross aeolian sands from the Cambrian (Amin) overlain by Permian glacial deposits (Al Khlata) with a high degree of heterogeneity. A combination of high viscosity oil and an extremely strong aquifer makes this field challenging. Early water breakthrough has traditionally been explained by rapid water coning, but recent data from under-balanced drilling operations highlighted that fractures do indeed play a role. This study aimed to explain whether this was a local phenomenon or a field wide characteristic, based on borehole image logs, openhole logs and production data from 16 horizontal and 15 vertical wells.
Faults/fracture corridors and dispersed fractures have no correlation to BSW (bulk water saturation) or gross production rates. However, wells with mud losses always produce at high BSW or have rapid water breakthrough. Recent data from under-balanced drilling operations also highlighted that fractures might play a role because significant water influx was focused within narrow intervals.
This apparent dilemma is resolved by noting that mud losses were reported only from a small fraction of wells, suggesting only a small fraction of faults are fluid conductive. Contrary to faults and fracture corridors, mega- fractures (large conductive fractures) have some correlation to BSW rate of increase. A possible explanation is that most fractures are clusters of shear fractures filled with sand and clay gouge, whereas some mega- fractures are opening mode fractures. It is not possible, however, to distinguish the opening mode fractures from gouge filled fractures from borehole image logs. In general fractures seem to play a minor role in water breakthrough because most fractures are not fluid conductive.
It appears that spud date is probably the main factor related to rapid BSW rise with recent wells being more prone to rapid water breakthrough. Other factors such as pump type, depth to FWL, and distance between wells also have some effect on BSW rise.
Measurement of the Particle Deposition Profile in Deep-bed Filtration during Produced Water Re-injection
Authors: Ali M. A. J. , Currie P. K. , Salman M. J. 
Published: December 2007

Abstract
An on-line linear X-ray apparatus has been used to examine deep bed filtration during water injection in Bentheimer sandstone core samples.Hematite particles suspended in brine were injected at different flow rates and concentrations to investigate the deposition profile.The X-ray attenuation is strongly related to the density; and therefore the amount of deposited material can quantitatively be estimated at any time and distance along the core sample.Deep penetration can be distinguished from external filtercake buildup. Permeability decline as determined by the pressure change and chemical analysis of hematite concentration were used to confirm the X-ray analysis.
Real-Time Downhole pH Measurement Using Optical Spectroscopy
Authors: Raghuraman B. , O'Keefe M. , Eriksen K. O. , Tau L. A. , Vikane O. , Gustavson G. , Indo K. 
Published: December 2007

AbstractA 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 get an accurate pH, the measurement has to be made downhole at reservoir conditions. Unlike potentiometric methods where 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 successfully applied 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 more accurate selection of appropriate completion materials and more effective planning for scale treatment and inhibition.
Well and Reservoir Management in a Giant Gas Oil Gravity Drainage Field: A Case History
Authors: Ali E. , Bergren F. E. , Saluja J. S. , Sinani I. S. 
Published: December 2007

Abstract
This paper presents the case history of a focused Well and Reservoir Management (WRM) effort in a giant densely fractured carbonate reservoir in Oman. The field is currently producing under the gas oil gravity drainage reservoir process. The fracture network in the reservoir is largely gas-filled and has a thin oil rim underlain by active aquifer. Horizontal and multilateral producers are positioned in the oil rim while aquifer influx is limited to the optimum rate by water withdrawal from flank water producers. Delicate balance of crestal gas injection, aquifer water withdrawal and oil production is required to keep the oil rim at its optimal position. As the fracture oil rim has been lowered over a period of several years, a large number of wells have gassed out and started to circulate injected gas. Initial analysis of the production trends indicated that additional compression capacity was required in the field.
An integrated WRM effort was undertaken in 2003 to manage this complex field. Active reservoir surveillance planning and execution was carried out to map current fracture fluid contacts across the field. Strategic well optimizations and recompletions were performed in selected wells to capture production from oil rim and avoid short-circuiting of the injected gas. Also, several gassed out intermittent producers and very high GOR continuous producers were shut-in. An eight-well production logging campaign provided better understanding of well and reservoir behaviour. Well integrity tests in over 110 wells further assisted in problem diagnosis and workover planning.
These focused WRM efforts have resulted in sustained 10% production gain over a one-year period. A major capex benefit was also realized when a better understanding of the reservoir and improved GOR performance of the field eliminated the previously perceived need for additional compression.
A New Method for Solving the Implicit Reservoir Simulation Matrix Equation
Authors: Watts J. W. , Shaw J. S. 
Published: December 2007

Summary
The dominant computational cost associated with implicit reservoir simulation arises in solving the matrix equation at each Newton iteration. This paper describes a new solution method based on a reduced matrix equation constructed using singular value decomposition. The reduced matrix equation is used as the basis of a preconditioner. The resulting preconditioned iteration generally converges in two to four iterations. The new solver can reduce solve times substantially.
Optimizing Stimulation Treatments in Straddled Completions
Authors: Willemse M. I. , Mostafa O. , El-Ashry M. , Abdallah I. , Sattar A. A. , Waheed A. , Conrad B. 
Published: December 2007

AbstractCompleting a producing zone(s) behind straddle packers is a common occurrence; hundreds of wells have been completed in this manner. Should such wells produce trouble-free and meet expectations, there is not much to ponder over; but if not, the options for executing an enhanced stimulation treatment have been limited. Generally, treatment has consisted of pumping and squeezing away the treatment into the perforations via the sliding side door(SSD) and hoping for the best. The preferred technique is to improve the injectivity into the perforations by "spotting" reactive fluids at the perforations or using some type of mechanical action such as "perforation jetting" to break up blockages in the perforation tunnels. This is only possible when perforations are accessible through the wellbore.These problems become more complicated if the zones of interest are sandstone reservoirs. A study1 in the late-1990s revealed a success ratio in the 30-40% range when treating such formations.This paper addresses such a scenario in which a dirty sandstone reservoir, not previously matrix-acidized, was producing at sub-par rates (declining to the point of being negligible). The zones were completed between straddle packers and were only accessible through SSD, 100 ft above the perforations.The prudent decision was to stimulate, but make all efforts to maximize the chances of success. Apart from applying the best practices in sandstone acidizing technology, a true fluidic oscillator (TFO) was included as a stimulation tool. This tool provides a continuous pressure pulse in the fluid system that allows solids buildup within the perforations to fatigue and break up while the acid system works on the rock matrix.The results from the treatment of this well were exceptional and will be detailed in this paper. The production improvement was 10-fold over its prestimulation performance.
Improving Management and Allocation of Gas Production in Maturing Reservoirs: A Multiphase Spinner Response Model for the 21st Century
Authors: Whittaker A. C. , Lenn C. P. 
Published: December 2007

Abstract
Conventional production log interpretation using a spinner assumes that the spinner responds to the holdup-weighted average velocity of the fluids traveling through the swept area of the spinner blades; however, the spinner tends to respond preferentially to the most dense phase flowing through it and so can be considered as a momentum-averaging sensor. This means that when fluids of markedly different density and velocity are averaged using the current best practice we may not be calculating the most accurate spinner velocity to be used in the production log interpretation. This paper examines alternative spinner averaging approaches and then evaluates the difference on synthetic, laboratory, and real downhole data sets. We conclude from this short study that there is potential to improve the current practice of spinner interpretation, especially in gas/liquid flows, and thus provide better data for gas production allocation and gas reservoir management. Further work is needed to develop this approach.
Reservoir Simulation Challenges for Modeling a Thin Volatile Oil Rim With Large Gas Cap in the Poleng Field, Kujung-I Oil Reservoir, East Java Basin, Indonesia
Authors: Forrest J. , Sukmana A. , Suhana W. , Asjhari I. 
Published: December 2007

Abstract
This paper explores the difficulties in modeling an oil rim with a large gas-cap using black-oil and compositional formulations. The example is from the Poleng field located in the Poleng Block, East Java Basin, Indonesia. This reservoir is a reefal carbonate system with a limited aquifer within the Kujung-I interval.
Production from the field commenced in 1975, was suspended in 1978 and re-activated by Kodeco in 1998. In 2002–03, a full-field study was conducted to re-evaluate the OOIP and OGIP and investigate future development options such as booster compression, gas and/or water injection, workovers, and infill wells. For this study, a new reservoir simulation model was developed based upon new/updated data. Two fluid PVT models (modified black oil and compositional) were also developed. At the start of the study, the operator felt that compositional formulation might be needed for modeling the gas injection processes. However, most of the work was performed using the modified black oil model because of computational speed consideration. The history match process showed that many simulation layers (grid blocks) were required to match the wells near the fluid contacts. Grouping some components in the compositional model was helpful to reduce run time, but the resulting equations of state (EOS) were generally not reliable for both the gas-cap and oil zones.
Simulation results indicated that an OOIP of 98.5 MMSTB was required to obtain a good history match. The original free gas-in-place was estimated to be 210.1 BSCF. The best future development option was a booster compression project. For a 10-year prediction period, additional oil and gas recoveries for the booster compressor were predicted to be about 1.7% OOIP and 19.0% OGIP compared to the base case. Gas injection was less favorable because it would defer some volume of the gas sales, while water injection, workover and infill wells resulted in very small incremental oil and gas recoveries. The main reasons for the low oil recovery are high residual oil saturations estimated from core analyses, reservoir heterogeneity, and gas fingering from the large gas-cap.
Successfully Sterilizing the Sulfate Bacteria With Ultraviolet Radiation in Produced-Water Treatment in Daqing Oilfield
Authors: Wang J. , Yang F. , Yuan X. , Liu B. , Wu H. , Sui X. 
Published: December 2007

Abstract
Now the chemical bactericides are often used to sterilize the SRB (sulfate reducing bacteria) in the treatment process of oilfield produced-water, but this method always accompany with disadvantage, such as lower efficiency, environment pollution, high cost, drug-fast of bacteria, and the side-effect of reaction with the other agent adding in water treatment. We Daqing oilfield should dispose about 500 million tons produced water, a great effort should do to get a bactericide method both of high efficiency and low cost to dispose such a mass of produced-water.
Development and Evaluation of High-Temperature Conformance Polymer Systems
Authors: Vasquez J. , Dalrymple E. D. , Eoff L. , Reddy B. R. , Civan F. 
Published: December 2007

AbstractConformance polymer systems have been successfully applied for many years to control undesired water production from hydrocarbon wells. However, currently available polymer systems present a number of limitations for high-temperature conformance applications (&gt; 300°F). Based on laboratory research, this paper documents the results of the development and evaluation of polymer gel systems used as sealants to shut off water production in high-temperature environments. The polymer systems were evaluated by their effectiveness to: (a) provide adequate gel time for placement (up to 400°F), (b) limit permeability to water at temperatures up to 375°F in sandpack flow experiments, and (c) provide long-term thermal stability in sandpack flow experiments at elevated temperature (up to one-year study).A commercially available polymer system that has been successfully used in field applications (up to 275°F) has been modified to extend its applicability up to 375°F. Recently developed base polymer, crosslinker, and retarder were tested successfully to extend the temperature range of applicability of this polymer system. Discussed are: (1) methodology used for gelation time measurement of polymer systems at elevated temperatures, and (2) laboratory results regarding gelation time of crosslinked polymer systems when varying temperature, base polymer concentration, crosslinker concentration, retarder concentration, salinity of mixing brine, and/or pH of solution.Additionally, this paper discusses and describes the dynamic flow through porous media experiments performed to simulate high-temperature / high-pressure reservoir conditions to evaluate the performance of polymer systems at elevated temperatures (up to 375°F). Specifically, this paper details: (1) the physical laboratory equipment and test conditions used for dynamic flow studies, (2) experimental procedure regarding short-term and long-term testing, and (3) the effect of temperature versus permeability reduction over time.
A volcanic reservoir: Facies distribution model accounting for pressure communication
Authors: Yamada Tomomi , Okano Yoshiyuki 
Published: December 2007

Abstract
A TCF-class gas field has been producing over decades in Japan. The reservoir body comprises stacked Rhyolite lava domes erupted under submarine environment. Porous network developed in each dome and rapid chilling by seawater caused Hyaloclastite to deposit over it. Although Hyaloclastite is also porous in this field, its permeability has been dramatically reduced by clay minerals. These reservoir facies are interbedded with Basaltic sheets erupted alternately and Mud sedimented while the volcano was dormant.
Based on stratigraphic correlation, multiple reservoirs were originally interpreted. Gas had been produced according to the priority assigned to each. However, it was noticed after 10-20 years of production that pressures of all unexploited units had been declining with variety of rates. We confirmed that by subsequent survey and decided to remodel the whole pressure system. As seismic data had not been informative, we made maximum use of the pressure data to resolve the nature of the communications.
We employed multi-point geostatistics to capture the complicated facies distribution patterns. Realizations are then calibrated against pressure history through a probability perturbation technique. A common difficulty of building proper stationary training image is further pronounced in modeling a volcanic reservoir. We solved this by iteratively adjusting a training image inferred from literatures until acceptable history match was reached with reasonable number of perturbations. Another issue was undetermined field extent. We settled this by stochastically populating a rectangular-parallelepiped modeling space of regular cells with pay and non-pay facies.
Resulted realizations closely simulate pressure history and look realistic in both facies distribution and field extent. They ascribe the uneven pressure decline to narrow channels of Rhyolite and confinements by Hyaloclastite. Finalized training image indicates more intensity in facies spatial variation than had been expected. Based on 20 realizations, roughly 15% of scatter was estimated in OGIP around the mean.