bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fracturing in Low Temperature Horizontal Wells
Authors: Wenjun Wang , Lin Wang , Xingfu Zhang , Sun Qingyou , Tang Pengfei , Haitao Wang , Zhongsheng Wu , Qingtiao Zhang 
Published: January 2010

Abstract
For shallow burying, the temperature is less than 30°C and low pressure in Putaohua formations in Chaoyanggou area in Daqing oilfield. Eight horizontal wells have been drilled in the area and need hydraulic fracturing to improve the oil production. Two challenges have to be faced. One is how to rapidly completely breaking for gel at the low temperature and improve the flow-back ratio of fracturing fluid after the fracturing, to reduce the formation damage. It is difficult to gel breaking quickly with conventional breaker in the conventional hydraulic fluid system under the super low temperature. Another one is how to improve the production of fracturing in the horizontal wells. According to the characteristic of the horizontal wells in the low temperature, low pressure reservoir, some new technologies have been used in the 8 wells fracturing jobs, such as a new type low temperature breaker, a new type of cleanup, mechanical isolation staged fracturing. In this paper, we provide details about these new hydraulic fracturing techniques applied in the horizontal wells. The Application in eight wells just as the following aspects: According to the study in the lab, a new type of fracturing fluid system has been used to suit the low temperature. At 30°C, after 4h later, the fracturing fluid was broken, and the viscosity of fracturing fluid is 3.5mPa.s. Mechanical isolation and staged fracturing with two packers is used in the horizontal wells with high efficient treatment about 4 to 6 stages per day to improve the oil production. Base on above all, we get the good result of oil production on the 8 horizontal wells, about 5.2 times higher than that on vertical fracturing wells at the same area. In this paper, we provide details about these new hydraulic fracturing techniques applied in the horizontal wells. These new technologies of fracturing provide an effective method for the horizontal wells in low temperature reservoirs in Daqing oil field.
A New Method to Discriminate Effectively the Influence of Water Injection and Natural Water Influx upon Reservoir Pressure System: A Case History from Cainan Oilfield
Authors: Nie Renshi , Jia Yonglu , Shen Nan , Qin Xusheng , Luo Xingwang , Zhang Wu , Liu Shun 
Published: January 2010

Abstract
Cainan oilfield is located in northwest China. The Jurassic sandstone reservoir with huge natural edge water and bottom edge water energy began to put into production in 1992 and injection in 1995. The volume of natural water is about 35 times the volume of reservoir. The reservoir production rate began to decline in 1999, at present, the production rate decline is very rapid, the average water cut is 79.83% and the recovery is 44.04%. There is a most pressing problems needed to address, which is that the water injection and the natural water influx how to influence the reservoir pressure system respectively, including the pressure maintenance level and the pressure exhaustion level, etc.
No reservoir engineering method is found to discriminate effectively the influence of water injection and natural water influx upon reservoir pressure system. A new method based on material balance principle is presented to resolve the above practical problem. Study is taken on from two aspects that fluids flow in and out of the reservoir. In terms of "in", the injection water and the influx water are divided into two parts according to their function in the reservoir: one part plays the role of maintaining the reservoir energy, the other plays the role of driving fluids. In terms of "out", the production fluids are produced due to two factors: one is the driving of the injection water and the influx water, the other is the reservoir energy depletion. After a series of deriving and deduction of complex formulas, the contributions of the water injection and the natural water influx to the reservoir pressure system respectively are calculated by use of the actual history production data. The results available can be used in guidance and reference to the next development adjustment for stabilizing production.
SGS Versus Collocated Cokriging Petrophysical Modeling: A Comparative Study in a Heterogeneous Gas Condensate Carbonate Reservoir
Authors: Tavakkoli Meyssam , Kharrat Riyaz , Inaloo Sahar 
Published: January 2010

Abstract
Building an accurate static model for entire field was the primary objective in the reservoir characterization and simulation. The goal was to develop a model with sufficient detail to represent reservoir discontinuity and petrophysical properties in field scale. There are different geostatistical methods for petrophysical modeling. Sequential Gaussian simulation (SGS) is a kriging based algorithm which simulates nodes after each other sequentially, subsequently using simulated values as a conditioning data. It is necessary to use standard Gaussian values in SGS method. Collocated Cokriging (C.C) is a reduced form of Cokriging, which requires knowledge of only the hard data covariance model, the correlation coefficient between the hard and soft (auxiliary) data, and the variances of the two attributes. In this study, porosity and permeability of a heterogeneous gas condensate carbonate reservoir are modeled first by SGS method. Than seismic attributes with high distribution density but low resolution are used as an auxiliary variable for porosity modeling from well logs data (limited distribution but high resolution).Determining which seismic attributes are meaningful to assist in the modeling and estimation process requires statistical analysis. In second step the modeled porosity by C.C is used as an auxiliary variable for permeability modeling. So in this method, seismic attributes have an indirect role in permeability modeling as well. A common practice usually involves the use of a cross validation scheme, where each well is removed sequentially, and its property is predicted using information from the remaining wells.
Integrating Production Analysis as a Plan of Pattern Selection for Chemical Flood Pilot Project in Limau Block, Pertamina EP
Authors: Nugroho Susanto Budi , Ardianto Reza Nur 
Published: January 2010

Abstract
Limau Block, operated by Pertamina EP lies in South Sumatera basin, located 90 Km Western part of Prabumulih. Consisted of eight fields, the first well was drilled in April 1951. The production reached a peak of 49,000 BOPD. The reservoir was divided into 22 layers mainly due to faulting. The pilot water flood operation was initiated in April 1991 by injecting water. Currently, Limau block is a mature oil field. By April 2009 production had declined to 10,000 BOPD. It is estimated that more than 80% primary reserves have already been produced and recovery factor has reached 36 %. Most of the reservoirs have been intensively produced over the life of the field and only a few of them are still producing today at low rate due to depletion.
EOR department tried to identify reservoir with remaining production potential that are candidates for Pilot Chemical Flooding Project, which will be the first Chemical Flood Project for Pertamina EP. The chemical selection is ongoing progress. It has become much more of a challenge for the team consisting of integrated Geophysics, Geology, Reservoir, Production, Process Facility, Project Management and Economic Evaluation.
This paper presents the result of Production Part as integrated analysis for Chemical Flooding. The analysis, which was performed by integrated analysis of production and injection, tracer test, well history and surface data, has identified inter well communication between injection well and production well. It shows that the most prospective candidate for Chemical Flood pilot project was S layer in Q-51 field, the pilot project was planned for inverted five (5) spot patterns and predicted breakthrough time was 90 days, it was also predicted a tertiary peak of 3,100 BOPD. Currently, Q-51 field, which had reached a primary peak of 20,600 BOPD and secondary peak of 2,000 BOPD, is injecting 36,820 BWPD through seven (7) peripheral injection wells and producing 31,031 BFPD through 13 production wells. This analysis is useful result as a part of countercheck for Geology and Reservoir Modeling regarding to the plan of Chemical Flooding Pilot Project.
Residual Hydrocarbons – A Trap for the Unwary
Authors: O'Sullivan T. , Praveer K. , Shanley K. , Dolson J. C. , Woodhouse R. 
Published: January 2010

Abstract
Residual hydrocarbons occur in a range of habitats and can take various forms: they may be oil or gas, they may be present within high-quality or poor reservoirs; and may appear as a single palaeo-column or as thin columns interspersed with beds of producible hydrocarbons. Residual hydrocarbons are sometimes easy to identify but when not recognised they may lead to optimistic reserves estimates.
This paper illustrates the range of habitats of residual hydrocarbons and provides techniques to enable their identification, such as novel log cross-plots and log overlays. In most cases the non-productive nature of the residual hydrocarbon can be confirmed using flow tests, with the possible exception of very low permeability reservoirs containing residual gas.
The results of not recognising residual hydrocarbons include (a) overbooking of reserves which may have serious commercial consequences, (b) the application of incorrect saturation-height functions, (c) pessimism in calculated formation-water resistivities estimated from water legs containing residual hydrocarbons, (d) lower effective permeabilities in water legs which may affect waterflood design, and (e) excessive expenditure on wireline formation testing and drill stem testing.
From an exploration perspective, residual hydrocarbons provide direct evidence of migrated hydrocarbons and/or breached oil fields and hydrocarbon loss due to regional post-migration tilt. Thus they provide important clues to the location of additional traps along the migration pathways.
We present examples of residual hydrocarbons from the Indian subcontinent and elsewhere. The subcontinent is particularly prone to the presence of residual hydrocarbons as many basins have undergone polyphase deformation and multiple periods of secondary migration and fill.
By raising the awareness of residual hydrocarbons, we hope that this paper leads to greater accuracy in reserves estimates, and perhaps even the discovery of additional hydrocarbons.
Monobore Design Optimises Slimhole Raageshwari Deep Gas Development
Authors: Jha Mihir , Singh Ratan , Vermani Sanjeev 
Published: January 2010

Abstract
The Raageshwari Deep Gas field, situated within Barmer Basin in the State of Rajasthan, India, was discovered in 2003. The field is a tight gas condensate reservoir, with excellent gas quality of approximately 80% methane, low CO2 and no H2S. The wells in Raageshwari Deep Gas field have tested at gas production rates in the range of 2- 4MMscfd and producing condensate gas ratios in 40-50 bbl/MMscf range. The condensate gravity varies across the field but approaches 60 API.
This paper discusses the fit for purpose monobore well design for Raageshwari Deep gas development wells. The design is suitable for handling fracture stimulation treatment, which is typical for a tight gas reservoir, by taking into consideration the suitability of the completion vis-à-vis surface and bottomhole treatment pressure during a fracture screen-out. The well completion supports the long term production from the gas condensate wells taking care of liquid loading issues. The paper also delves into the various well designs that were implemented during the appraisal phase and advantages offered by the current monobore well design especially in de-coupling well completion from well stimulation activity thus reducing the overall field development cost.
Determination of Wettability and its Effect on Oil Recovery in a Carbonate Rock of an Offshore Field Under Ambient and Elevated Temperature
Authors: Kumar Rajesh , Verma S.K. 
Published: January 2010

Abstract
Wettability indices were derived using centrifuge capillary pressure tests on two sets of core samples of carbonate reservoir of Mumbai High, an Indian offshore field. One set of samples were aged in crude and then displaced with Isopar mineral oil so that the test sequence could be conducted at ambient temperature. Another set of samples were aged in crude and the subsequent testing conducted using crude oil at elevated temperature. The wettability indices indicated intermediate wettability character with slightly water wet to slightly oil wet and the field is expected to yield higher oil recovery. Moreover, similar wettability indices derived from both sets of tests indicated that displacing crude with Isopar left the samples in a reservoir representative wetting condition. Hence subsequent testing using Isopar at ambient temperature would yield valid results at much lower cost, and in a much faster time frame, than conducting tests at reservoir temperature and pressure with crude oil.
Depositional Environment and Sequence Stratigraphy of Eocene Reservoirs, Assam Shelf, India: A Multiwell Log Study
Authors: Bora D. S. , Baruah Neelimoy , Shrivastva Chandramani , Bharali Binayananda 
Published: January 2010

Abstract
Although the Palaeocene-Eocene reservoirs of the Assam shelf have been prolific producers of oil and gas, the production profiles of various fields have caused concerns because of their departure from the geological model originally envisaged. An attempt is made to understand the temporal and spatial reservoir heterogeneity within a broader depositional model framework using micro- resistivity image and open hole log data from four fields in the assam Shelf; Baghjan, Katahloni, Bhogpara and Nahorkatia. Using image data, whole cores, dip patterns, openhole logs, image derived neural network facies and image derived textural facies, the key reservoir facies associations are identified. Facies associations in different wells are made use of to reconstruct depositional sequences, which enable to conceive a broader depositional model for the sedimentation of major Plaeocene to Eocene formations, namely Langpar, Lakadong, Narpuh, Prang and Kopili.
This study infers marginal marine to coastal plain channelized sedimentation for the Langpar formation with reservoirs likely to be oriented in a NW-SE to E-W direction. These basal clastics are overlain by lagoon–barrier island to coastal plain channel environment of the Lakadong formation with reservoir orientation along E-W to NW-SE direction. Beach-strand plain to chenier plain depositional environment is encountered in the Narpuh formation with the reservoir appearing to have an extension along N- S to NW-SE direction. Overlying Prang and Kopili formations are inferred as restricted marginal marine deposits. The Prang shows occurrences of carbonate facies whereas the Kopili shows feeder channels facies of thick argillaceous sequence. Overall, the Eocene-Oligocene petroleum system seems to have been deposited in a marginal marine depositional setting. Analysis of depositional units in a sequence stratigraphic context suggests that the overall sequence has evolved in a transgressive system. Using a sequence stratigraphic framework allowed us to better define reservoir distribution patterns of the Assam Shelf, and these facies associations may prove useful in future reservoir modeling studies.
Permeability Transforms and Geologic Modeling of The Heera Field, India
Authors: Bhattacharya S. , Rao N. S. , Datta-Gupta Akhil 
Published: January 2010

Abstract
Permeability predictions are a critical aspect of reservoir description and are particularly challenging for carbonate reservoirs because of the complexities rooted in diagenesis, grain size variations, cementation etc. Conventional multiple regression techniques very often yield unsatisfactory results.
The paper proposes a simple approach to obtain permeability correlations in heterogeneous carbonate reservoirs using commonly available well logs. The approach follows a two-step procedure. First, the well log data is classified into electrofacies types. This classification is based on the unique characteristics of well log measurements reflecting minerals and lithofacies within the logged interval. A combination of principal component analysis and model-based cluster analysis is used to identify and characterize electrofacies types. Second, a non-parametric regression technique has been applied to predict permeability using well logs within each electrofacies. The main advantage of this technique is that it is primarily data driven as opposed to model driven and does not require a priori specification of functional forms, which makes conventional multiple regressions difficult.
This method has been successfully applied to a heterogeneous carbonate reservoir, the Heera and the South Heera field in offshore India. The field is producing for over twenty five years and a major redevelopment effort is ongoing to improve production from the field by targeting the bypassed oil. Geologic modelling and flow simulations are important aspects of the redevelopment planning efforts. Our proposed approach results in improved predictions of permeability using commonly available well logs. The permeability correlations were incorporated into the geologic modelling to generate field-wide 3-D distributions of permeability. A scaling of the cumulative probability distribution was carried out to modify these permeabilities to account for well test data. Preliminary simulation runs indicate that the 3-D geolgic model is able to adequately reproduce the pressure trends and the waterfront movement in the reservoir. Detailed history matching is currently in progress.
Geosteering Long Horizontal Holes in Abu Dhabi Heterogeneous Carbonate Reservoirs
Authors: Dawoud Ahmed , El Mahdi Ahmed , Ayoub Mohammed , Bin Saad Mohamed , Al Marzouqi Khalid , Hendrawan Irfan , Daif-Allah Samy , Khalil Ghazi 
Published: January 2010

Abstract
Field development of a heterogeneous carbonate reservoir in Abu Dhabi-United Arab Emirates focused mainly on the geo- steering technique to penetrate the target level of the reservoir and drill and place long radius open horizontal hole for final completion as single producers or injectors. Tough drilling environment of natural islands, manmade islands, shallow and deep waters based on poor seismic data and depth uncertainties added to difficulties of predicting the setting depth of the 7" liner before geosteering operations of the open horizontal hole. Wells clustering to minimize drilling and surface facilities foot prints, top drive drilling using rotary steering system (RSS) techniques together with real time LWD helped to better control trajectory and placement of the horizontal holes as planned. Fluid identification in pilot holes as well as across the horizontal holes was successfully acquired to capture necessary reservoir fluid samples.
Geosteering operations and the experienced difficulties of placing the horizontal holes as planned were affected by rock heterogeneity, rate of penetration, mud system, and real time monitoring and follow up. The implemetation of geosteering and real time data acquisition was supervised by the team abd resulted in timly decisions for proper action and achievement of the target development plan. However, depth uncertainties resulted in improper placement of three wells but these well were worked over to correct the location. In addition, coiled tubing accessibility problems have been experienced following production and injection commissioning. This problem was attributed to the undulating horizontal hole and the well completion technique.
This paper presents a field case of drilling and geosteering of long radius open horizontal holes and wells completion. It points to possible reasons for experienced poor coiled tubing accessibility and the lessons learned for future development.
Novel Microbial Process for Mitigating Wax Deposition in Down hole Tubular and Surface Flow Lines
Authors: Rana Dolly Pal , Bateja Surendra , Biswas Susanta Kumar , Kumar Ashok , Misra Tilak Ram , Lal Banwari 
Published: January 2010

Abstract
Many oil fields producing waxy crude, face severe wax deposition problem in down hole tubulars and surface flow lines. Sometimes this problem is also encountered at the face of producing zone in the well bore region due to changes in temperature & pressure conditions. This problem frequently results in complete blockage of the crude passage and poses severe production problem. Conventional methods such as thermal, magnetic, mechanical scraping, solvent cleaning and chemical treatment etc. are not only cumbersome, costly and hazardous but provide only temporary respite. Two separate microbial systems, capable of mitigating the vexed problem of paraffin deposition in oil well tubulars and surface flow lines have been developed.
The microbial system for down hole tubular comprises of paraffin degrading bacterial (PDB) consortium named as PDS-10, nutrient supplements and growth enhancer. Laboratory studies showed significant reduction in pour point and flow behaviour of the crude. The process is effective up to 900C but maximum efficiency was observed at 550C. Field trial in 100 wells of different fields of Western & Eastern sector has shown that the treatment not only checked the paraffin deposition in all the treated wells but also improved oil production by 20-80 % in many wells. Most of the treated wells flowed without any wax deposition for 6-8 months after the treatment.
For flow assurance in surface flow lines bacterial consortium named as FIB-19, which shows high degree of wax degradation capability has been developed. The bacterial consortium is aerophilic, mesophilic and remains active upto 430C. Field trial in surface flow lines of twelve wells of Ahmedabad Asset was quite successful resulting in elimination of requirement of line flushing for considerable time along with reduction in pressure in the flow line. The average period of effectiveness of the jobs has been found to be around 4-5 months.
Laboratory Investigation of Low Salinity Waterflooding as Secondary Recovery Process: Effect of Wettability
Authors: Ashraf A. , Hadia N. J. , Torsæter O. , Tweheyo M. T. 
Published: January 2010

Abstract
Laboratory studies along with field tests conducted over the decade reveal that reducing the salinity of water injected into reservoirs improves the oil recovery. Different phenomena e.g. increase in pH (alkalinity), fines migration, multi-component ionic exchange, etc., have been proposed by researchers for improved oil recovery during low salinity waterflooding (LSW). Though LSW has attracted attention among reservoir engineers as tertiary recovery process, limited studies have reported the potential of LSW as secondary recovery process. Also, the relationship between reservoir rock parameters such as wettability, rock minerals, etc. and oil recovery is not well established for LSW.
The objective of this paper was to investigate the relationship between rock wettability and oil recovery with low salinity water injection as secondary recovery process. Coreflooding experiments have been performed at room conditions on Berea cores with four different wettabilities ranging from water- to oil- wet. Brines and n-decane were used as displacing and displaced phases, respectively. The results showed that, for all the salinities, oil recovery increases as wettability changes from water- to neutral- wet conditions. Further change in rock wettability from neutral- to oil-wet condition resulted in decreased oil recovery. It was also interesting to observe that oil recovery is higher for LSW as compared to high salinity waterflooding when used as secondary recovery process. Increase in pressure drop and hence decrease in effective permeability was also observed during LSW process in most of the cases considered.