bluuebunny/crossref_metadata_2025 huggingface dataset:
Profile Controlling by Horizontal Well Completion Strings with Inner-located Nozzle
Authors: Li Liangchuan , Liu Huiqing , Zhang Hongling , Wang Qing
Published: July 2010

Horizontal well has been used successfully in small block and offshore reservoirs and reservoirs with bottom water for cresting control. Watering-out profile along horizontal well in the reservoir with bottom water can be identified by production logging or by production history matching. The logging information shows that the profile is related to the formation permeability distribution in the well, and the flowing disturbance between high and low permeability interval has been tested from room experiment in a square sand pack model with vertical heterogeneity, it has been shown that start-flowing for displacing fluid though low permeable part in heterogeneous formation depends mainly on the permeability ratio of high to low. The ratio limit is about 3 for light oil reservoir, and little fluids will flow in low permeable part of the perforation interval for commingled injection or producing well. Well completion strings has been designed with concentric tube, filtering cotton coated for outer slotted wall and nozzle located in the inner wall. There may be empty between formation sandface and the well completion strings, and gravel packing and/or packer can be used. Variable mass flow dynamic models have been built based on momentum balance for two channels, and fluids flow transfer between the neighbor channels has been included, flowing relation with watering-out profile character and fluid flowing though gravel packing and/or packer barrier will be coupled in the model. Finite difference scheme has been used to solving the equations and coding procedures, pressure and flow rate distribution in the two channels can be calculated, flowing rate and pressure distribution are not symmetry because of interference of fluids transfer between channels. Different nozzle size and location can be determined for the watering-out profile changing, outer gravel packing and packer spacing can be designed also. The method has been used in the designing for well completion strings in Jidong oil field, and production performance of the well has been shown that the completion strings with inner-located nozzle in horizontal well is successful.
A New Deliverability Testing Method for Gas Condensate Wells
Authors: Shi Juntai , Li Xiangfang , Shi Depei , Xu Hanbing , Li Baozhen , Zhou Jianrui
Published: July 2010

In the process of well testing on gas condensate well, if the condensate liquid retrogrades from gas phase, which will adhere to the surface of the rock, the key reservoir parameters would vary, such as the permeability and the skin factor. The changes of reservoir parameters could affect the deliverability of a gas condensate well, by changing the coefficients of A and B in the deliverability equation. These changes make it inapplicable to use the deliverability equation for a conventional gas well to interpret the deliverability of a gas condensate well.

In view of the problem above in the process of well testing on gas condensate well, the model in this paper was built up in view of different pressure region, and could reflect the deliverability equation under the specific testing condition, so it could interpret the deliverability of a gas condensate well under different production stages. A new method to model and construct a deliverability equation with variable coefficients or many independent deliverability equations, which can represent the performance of well, was put forward in this paper.

Through applying the deliverability test method put forward in this study to a case, results obtained from this method keep consistent with the real testing data, so the deliverability of a gas condensate well obtained by using this method in different process of production can be correctly evaluated.

The created deliverability equation could reflect not only the characteristics of gas reservoir testing and dynamic performance, but also four-dimensional changes of rock properties and flowing parameters of reservoir fluid, so the well performance in the future could be more accurately predicted.
Investigation of Foam Properties and Its Action on Flow Improvement of Heavy Oil
Authors: Qiang Jing Jia , Li Yanfang , Yang Xue , Zhang Zhihong , Yao Jianhua , Zhu Hongjun
Published: July 2010

Many difficult technological problems for heavy oil to be produced and transported have occurred due to its high viscosity and serious adhesion onto the flow channel. The fact or phenomenon that the output of foamy heavy oil is higher than that of foamless one implies that the foam existing in the foamy oil has an obvious action on the flow improvement of heavy oil. The major purpose of this study is to investigate and analyze the foam properties, and to verify its action on the flow improvement of heavy oil. Based on the evaluation of foamability, stability and comprehensive performance of the foam, and combined with the analysis of the effects of pH value, mixed salt of NaCl and CaCl2, temperature and MHZ crude oil on foaming comprehensive performance, the optimal formula of foam solution has been screened by using Waring Blender and orthogonal experimental methods. The rheological properties and viscosity-temperature characteristics of various foams, MHZ heavy oil and its foamy oils were measured and analyzed by using rheometer Rheolab QC. The flow improvement mechanism of heavy oil with foam has been discussed by combining with the analysis of the foam properties and its microstructures.

The results show that obvious synergistic actions exist among different foaming agents. For 200ml of the optimal foam solution, its foaming volume is 620ml at the room temperature, the foam half-life is 494min, the foaming composite index is 229710ml·min, and it has stronger resistances to acid, alkali, temperature and oil. The foams and foamy oils show the properties of Non-Newtonian fluid at the studied temperature range and obey the power-law fluid-flow model. The law of the viscosities changed with temperature for different foamy oils is very similar. The higher the temperature and/or the content of the foam solution is, the better the flowability of the foamy oils is, and their highest viscosity reduction rate can reach 96% or above. The apparent viscosity is insensitive to the change of temperature and/or content of the foam solution at the temperature range of 20°C to 30°C. Thus the flow improvement mechanism of MHZ heavy oil with foam can be attributed to the effects of disintegration, isolation and lubrication of the foam on the oil and its flow channels. Therefore, this study provides a theoretical foundation for the development and application of new technologies on the flow improvement of heavy oil.
Step Change in Injury Rates through Integrated Operator and Service Company Safety Management
Authors: Krus Harrie , Johan Krone Friedel , Christiansen Dave , Mientjes Ron , Dawson Mark , Flores Juan , Landgrave Stephen , Alyusuf Jihaad
Published: July 2010

The Wells department in Brunei Shell Petroleum (BSP) achieved 1 year without a recordable case injury to any of its combined staff and contractor work force. Throughout the year, there was an average of some 350 BSP Wells staff and 750 contractor staff that participated in BSP's land and offshore oilfield activities. In this article the authors' hope is to convince you to adopt similar processes in your organization to improve the safety performance of your operations. Furthermore, the processes outlined in this paper can be used immediately by any operator, group of operators, and contractors who work co-operatively together with the aim of reducing injury rates in their circle of influence.

Since the initial implementation, the BSP and the Contractor Group safety statistics have improved dramatically over the last 2-year period as can be seen in Figure 1 below.
Low Resistivity Pay Evaluation Using Triaxial Induction in Offshore South China
Authors: Cai Jun , Wu HongShen , Shusheng Guo , Guan Hui , Desport Olivier
Published: July 2010

Low resistivity pay is common in China and presents a difficult interpretation challenge. One possible cause is sand-shale laminations where the presence of conductive layers dominates the resistivity measured by conventional resistivity tools which mainly sense the horizontal resistivity component. Those low resistivity layers may consist of shale or fine grain sands with high bound water. They create resistivity anisotropy and if not detected, it may result in missing or underestimating the pay.

In order to characterize laminated formations, the vertical resistivity needs to be measured and this can be achieved using a 3D induction tool. This tool uses triaxial transmitters and receivers at various spacing to measure a tensor which is inverted to extract horizontal and vertical resistivity.

Those resistivities are then used in a model based interpretation to compute the resistivity of the sand lamination and thus the saturation. Being a model based interpretation, the model needs to be validated. Some effects can be accounted for such as intrinsic shale anisotropy or dispersed clay in the sand layer. Other effects such as highly resistive cemented layer may not be compensated for and need to be identified. This paper describes some of the effects through log examples from offshore China.
Adaptive Analysis of Lifting Technology for Horizontal Wellbore in Low Permeability Oil Field
Authors: Wang Hongxing , Baoming Shen , Dongyuan Ge , Tong Wang , Baozhong Zhang , Cao Yanling , Zhu Xiufeng , Hong Sun
Published: July 2010

For 5½″casing medium curvature of radius in the horizontal wells, sucker rod pump can not be down to the horizon part of the wells. It can not overcome the eccentric wear problems of rods and pipe. The no-rod lifting technology for horizontal parts of horizontal wells and flowing pressure distribution, and inflow performance relationship in low permeability oil field were studied in this paper. The theory of no-rod lifting technology is that the linear electric motor, horizontal pump and oil tube are connected together. Then they are put down to horizontal section. Electromotor stator is linked with oil tube. Mover reciprocates axially to drive horizontal pump movement to realize oil pumping. Based on ground test data, electric motor can return to natural state without force after traversing deflection point in horizontal well. Besides, horizontal pump efficiency was high under horizontal condition. Results of field test for three wells showed that there was no stick when the pump went down. Average pump efficiency was 95%. Average system efficiency was 20.3%.It was found that Horizontal Electric Submersible Piston Pump can be down to 5½″ casing medium curvature of radius in the horizontal wells in any position, not only to achieve lift efficiency, but also to achieve high pump efficiency. It avoided the problem of pump inspection caused by off-center wear of casing and sucker rod. This system can enhance oil production of horizontal well by controlling reasonable flowing pressure.
Geographical Information System Applications In EP Business
Authors: Cheng Yuhua , Puasa Zurinah Yen , Endot Ernyza
Published: July 2010

GIS (Geographical Information System) technology has been applied to each phases of Shell E&P business process. In Shell Group, GIS is standard global tool for GIM(Geo-Information Management), Mapping, Spatial Analysis, dynamic objects tracking, environmental assessment, oil spill response etc. GGAI (Global GIS Architecture Implementation) is globally adopted in Shell operating units to deliver standardized physical infrastructure and processes. Further more, 24 hours Global GIS helpdesk has been established to assist internal GIS users when they need help in using GIS data and tools. Shell has more than 1000 GIS users located in 20+ countries. With GIS users increasing, Web GIS based ArcGIS server has provided a cost-effective solution for ‘light weight’ users. This poster will briefly introduce the major applications of GIS technology and values added to Shell EP business.
Optimizing Performance in a Deepwater Environment: Gabon & Equatorial Guinea
Authors: Saicic Petar , Gordon Jeanette , McAllan Robert
Published: July 2010

This paper reviews an operator's deepwater drilling campaign in Gabon and Equatorial Guinea and the principles that were established to ensure success through optimized performance.

Due to the economics involved in deepwater drilling notably the availability of suitable high specification drilling units, (and the corresponding high operating costs and mobilization times) operators with short exploration campaigns are responsive to considering the use of lesser specification vessels with a different well construction philosophy as a means of both optimizing performance and safely undertaking a project.

For this particular case study, the operator implemented current proven technologies in new ways to extend the previously regarded equipment limitations of a vessel thus providing a fit for purpose and safe solution to the financial and operational roadblocks which could have hampered the project. Specifically the implementation of surface BOP's on a dynamically positioned drillship along with riserless drilling and evaluation of a shallow gas reservoir well.

The key principles employed that ensured a successful campaign were; Trust in the teams ability to do their jobThorough well planning and risk assessment processesEstablishing a high objective. i.e. "technical limit"Adapting and innovating to a given situationLogistical planningEmphasis on accurate cost trackingEstablishing strong vendor relationships.

The principles employed in this particular success case can be implemented for any project or task in a variety of industries or applications. Ultimately success was attained through thorough planning and subsequently successful execution of the plan.

The result was that this operator was able to drill 5 wells in the same amount of time as other operators had taken to drill only one well. This paper will detail how world record breaking performance in a deepwater environment was achieved.
A Quick-and-Novel Method in Evaluating the Producing Performance of Single-Layer in the Multilayered Sandstone Oilfield
Authors: Du Qinglong , Zhu Lihong , Guo Junhui , Liying Wei , Yin Shumin , Zuo Songlin , Tang Jinrong , Cao Weifu , Liu Baolin
Published: July 2010

In a multilayered and heterogeneous sandstone oilfield, the corresponding adjusting measures could be taken to improve the displacement efficiency only when the producing performance of every single-layer is evaluated. As to Lasaxing Oilfield, while most of the reservoirs have been watered out, a novel methodology used to evaluate the reservoir performance based on the fine geology and Darcy's law is promoted in this paper. The producing and injecting wells are taken into an integrated system in the novel method. And based on the balance of injecting and producing in the well group, the injected water of a single-layer is allocated to wells affected by injecting according to the reservoir and developing factors, and the producing rate and thus the water cut in every individual reservoir could then be determined. And the water-cut predicting model is also promoted in this paper based on numerical simulation of reservoir conceptual model. The corresponding software is also programmed. And the method is verified by the calculating of 1200 layers of 150 wells in Daqing Oilfield, where the accuracy is more then 75%. And the WOF technology is used in 35 layers of 12 wells with high water-cut, which leads to a good result.
Hydraulic Flow Unit Based Permeability Characterization and Rapid Production Prediction Workflow for an Offshore Field, South China Sea
Authors: Guo Shu Sheng , Cai Jun , Zhou Jing , Niu Yu Qiang , Feng Li Xiang , Yu Yin Hua , Khong Chee Kin
Published: July 2010

This paper presents a case study of hydraulic flow unit (HFU) based permeability characterization and fast production prediction for an offshore field, South China Sea. The aim is to integrate cores, petrophysics logs, formation tester and drill string well test (DST) data together to build a generally applicable workflow for rapid production prediction immediately after logging, in order to facilitate the decision making of the drill stem testing and completion. Overall productivity of a well and productivity of each zone is critical information for well evaluation. Based on a quick yet reliable answer, operators can decide whether the well should be tested by DST /completed. If the prediction is within the acceptable accuracy range, the number of zones to be tested could be reduced. Therefore well cost can be greatly saved.

The major challenges are facing in this field are: highly laminated sand/shale sequences, strong heterogeneities, complex por-permeability relationships, and different scales of different measurements. Based on the field geological settings, total four sub areas, two sub zones were delineated. Different HFUs were identified from core data for each area and zone. The porosity-permeability models were built in each HFU. The permeability output was calibrated by formation tester interpreted effective permeability to get calibration scale factor. Based on the scale factor, a workflow was then set up to predict the production for new wells, from either core data or petrophysical data, depending on the data availability. Three DST results were used to validate the results from this workflow, giving great confidence of the applicability in the study result (the prediction accuracy is within 20% range). This case study brings following values: a quick production prediction workflow has been set up for this field; and the methodology applied is not limited to this specific field but applicable to other fields with similar formation types.
Solid Expandable Tubular Combined With Swellable Elastomers Facilitate Mulitzonal Isolation and Fracturing, With Nothing Left in the Well Bore to Drill for Efficient Development of Tight Gas Reservoirs in Cost Effective Way
Authors: Anjum M. Ghufran , Shafeeq Umair , Younas M. Avais
Published: July 2010

Expandable technology applied as a production string, facilitates increased fracturing, and improved conductivity, enhanced hydrocarbon production. A solid expendable system can provide an integral component in new wells and re-entry wells where low permeability reservoirs need isolation and separation for selective hydraulic fracturing or re-fracturing. This system can optimize the fracturing parameters by maintaining large diameters and providing seals for selective multi zone or zonal isolation purpose. Expandable systems provide an efficient means to isolate trouble zones and preserve hole size when well-bore tapering hinders completion. Expandables used to repair the casing have extended the life of these wells without compromising the necessary hole size.

Before swellable, inflatable packers with mechanical shifted sliding sleeves were used for isolation, as well as to provide a frac and then production flow path. These systems typically require multiple trips in and out of the well bore, and tie up both rig and frac equipment, adding to higher project economics. In the past few years, an assortment of single-trip, multiple-zone isolation completion systems (modified production packers coupled with ball-actuated farce sleeves) have been developed. The application of a solid expandable system realized another step in adding value and further bolstered project economics by unlimited number of zones or sections to be fraced because no sliding sleeves or incrementally sized balls are required.

This paper explains how solid expandable system with swellable technology can be helpful to facilitate multizonal isolation, first time fracturing and re-fracturing, multi zone fracturing, and large diameter production conduits. Integration and system development of this technology will also be discussed to illustrate the effectiveness of solid expandable system in cost effective way.
Modelling a Series of Non-Aqueous Field Scale Inhibitor Squeeze Treatments in the Heidrun field
Authors: Vazquez Oscar , van Ommen Theo , Chen Ping , Selle Olav Martin , Juliussen Bjorn , Kolstø Erlend , Gustavsen Øyvind
Published: July 2010

When a conventional aqueous squeeze treatment is not suitable for preventing scale formation, a non-aqueous treatment may be applied. Generally, this type of treatments includes a non-aqueous phase and can be divided into different types based on the delivery system. Despite the name, most non-aqueous treatments still contain some water, due to the scale inhibitor hydrophilic nature; it only truly dissolves in water.

The main purposes of this paper are, firstly to model a series of polymer non-aqueous scale inhibitor, SI, squeeze treatments deployed in the Heidrun field in the Norwegian sector of the North Sea. Secondly, investigate alternatives to optimize the squeeze design by studying the effect of the overflush. And finally, show the workflow to build the input data model from the available field data. All the field treatments designs under study included the injection of an amphiphilic solvent phase as the scale inhibitor carrier phase and a diesel overflush.

The simulation and optimization calculations were done using a specialized near wellbore model for scale treatments. The simulation study consisted in matching the well water cut for the time of the treatment, followed by the derivation of a pseudo adsorption isotherm, which was used to describe the SI retention in the formation. Heidrun core flooding data and SI return data were used to build the input model. Finally, based on the created input models, a sensitivity study on the effect of the overflush on the squeeze lifetime was carried out.
Creating Opportunities from Challenges in a Difficult Environment: The Role of the Petrophysicist
Authors: Azuka Akam Somadina , Maher Tom , Goring Ken , JianChun Liu
Published: July 2010

This paper recounts the challenges faced by an integrated study team working on fields in offshore Malaysia. These challenges included flat production since last rig activity, unwanted water/gas production and modeling difficulties, which led to poor history matches.

The team petrophysicist faced specific technical challenges. The reservoir rock (as evident from cores) is very shaly, with thinly laminated hydrocarbon bearing sands in multiple stacked reservoirs. In addition, the low salinity of the formation water further reduced the contrast between pay and non-pay rocks. The reservoirs are relatively shallow with minimal consolidation, and large washouts commonly affected density/neutron logs. Consequently, fluid typing, fluid contact identification and derivation of petrophysical evaluation parameters posed significant technical challenges.

The paper presents three selected cases that inspired unusual approaches to overcome the foregoing difficulties and also rigorously challenge/support static and dynamic models.

Case One will demonstrate how adapting an innovative permeability prediction method – the Flow Quality Indicator (FQI) Concept - helped to resolve history-matching difficulty in Dynamic simulation. The FQI concept has since been tested successfully in other clastic depositional settings in Brunei and Nigeria.

In Case Two, the model integrity was improved through checking for consistency in input and model data. In particular, a comparison of the conventional wireline saturations and the core-derived saturation profile proved the value of thin-bed evaluation. Further check was to ensure that the resultant group of saturation-height tables covered the full range of rock quality before assigning to model layers.

Case Three draws from the recommendation in Case Two for thin-bed evaluation and demonstrates how reservoir value was maximized in thinly bedded sands. Consequently, hitherto production accounting problem was resolved.

In conclusion, this paper will demonstrate that a challenging environment brings out the best in the team Petrophysicist to make contributions that do result in business game change.
CO2 IOR on North Sea Chalk: Laboratory Experiments at Reservoir Conditions
Authors: Olsen Dan
Published: July 2010

The performance of CO2 IOR on low-permeable chalk was tested in two reservoir condition experiments modelling the Syd Arne oil field of the Danish North Sea. Conditions were Pfluid=380 bar, NOB=120 bar, and T=115 °C. A core sample with porosity=29.4 %, and kg=1.6 mD was used. Fluids were recombined live crude oil, simulated formation water, and pure supercritical CO2. The oil-CO2 system was above the minimum miscibility pressure.

Starting at an Swi of 0.147 PV, a water-flooding was conducted that resulted in the production of 0.597 PV of oil and an Sorw of 0.256 PV. This represents the end-point for the water-flooding experiment, and was the starting point for the CO2-flooding experiment. CO2-flooding produced only water until injection of 0.476 PV of CO2 where breakthrough of a miscible oil+CO2 phase occurred, followed by a sharp rise in production of oil+CO2 without detectable fingering. At breakthrough the miscible oil+CO2 phase had high contents of hydrocarbon, which gradually decreased. After injection of 1.51 PV of CO2, the cumulate oil production during CO2-flooding was 0.197 PV and the sample had reached an SorCO2 of 0.059 PV. After this no further oil production occurred. The efficient sweep of the CO2-flooding is attributed to increased viscosity of the miscible oil+CO2 phase and to transverse layering within the sample. Corrosion and compaction of the rock sample were insignificant. Permeability change was absent within the precision of the experiment.

The experiment indicates a potential for CO2 IOR to produce significant amounts of oil from low-permeable chalk, even after a water-flooding operation. It further indicates adverse effects from corrosion and compaction to be limited.
Thermal Recovery Technology Research and Application of Thin Heavy Oil Reservoir
Authors: Wang Guofeng , Jiang Deying , Zhao Haijing , Qu Yingxin , Chen Yong , Qin Fenglan , Li Yingxin , Shao Kuilong
Published: July 2010

According to the geological characteristics of heavy oil reservoir in the western slope area of Daqing oilfield, the thermal production numerical simulation research was done, the parameters of steam soaking and steam flooding under different effective thickness were optimized, and also the production index of reasonable thermal production exploitation project was predicted. The results showed that when the effective thickness was 3m, the reasonable steam injection rate, steam injection strength, bottom steam dryness fraction and soak time were 120t / m, 100t / d, 50%, 5d in the phase of steam huff and puff. In the phase of steam flooding, reasonable steam injection strength, bottom steam dryness fraction, production factor and flooding conversion time were respective 390t / m • km2 • d, 50%, 1.4t / t, at the end of the fourth cycle. Seam stimulation field test started in the test area at the end of 2007, in the first cycle, the average single-well injected steam 841t, produced 222 days, produced fluid 398t, oil-producing 244t, oil/gas ratio 0.29, the development effect was basically consistent with predicted results.
Successful installation of Straddle With Inflow Control Device To Restrict Gas Influx, A Case History From The Heidrun Field
Authors: Nielsen Marianne Gudmundseth , Auflem Inge Harald , Svela Per Einar , Porturas Francisco
Published: July 2010

The Heidrun field is approaching late life production and several wells have increasing gas oil ratio caused by gas break through. Likely gas inflow is through high permeability streaks or gas cap being drawn into the wells. The Heidrun processing facility is limited on gas processing capacity and hence wells are closed in when the gas oil ratio is too high.

The candidate well was chosen based on results from a production log run in 2008 showing high gas influx in the top screen sections. Interpretation was uncertain as to whether there was only gas or if oil also was coming from the interval, so to completely straddle it off was not a desired option. In order to reduce the gas influx, but maintain some oil production from the dedicated interval, it was decided to install a straddle with inflow control devices (ICD). This way a limitation was imposed on the drawdown of the interval, but the interval would still contribute. The results from the operation exceeded our expectations by far and the asset is now looking for other candidate wells.

This paper describes the method used to determine the size and number of the nozzles in the inflow control device, the length of straddle and technology used to install it. Further it will show the results of the operation until now and potential use of this technology in old and new wells on the field.
Successful Through-Tubing Gravel Pack Unlocks Production in Mature Fields Offshore Brunei
Authors: Shaikh Karim , Adesegha Rotimi , Talib Norliny
Published: July 2010

Sand production remains one of the key risks to maintaining field production rates and maximizing ultimate recovery from mature fields offshore Brunei. Due to the operational challenges and the HSE risks resulting from sand production in the surface facilities, sand producing wells are shut-in prematurely, locking-in well production and remaining hydrocarbons. Very fine, poorly sorted formation sands and uncertainty in general about formation sand particle size distribution leads to a challenge in designing robust downhole sand control completions. Sometimes we get it wrong resulting in the failure of the original sand control completion.

Low cost options to remediate sand production through the deployment of wireline conveyed thru-tubing standalone screens are typically not reliable in this environment and often considered as a last resort option. In addition most of the existing wells are old, have well integrity problems and completed with small 3-1/2" tubing that limit the application of mechanical thru-tubing options. Expensive rig interventions to workover or redrill sanded out wells are typically not justified by the low remaining reserves.

To overcome these challenges Brunei Shell Petroleum embarked on an effort to identify and field test a viable rig-less remedial sand control solution for unlocking production and maximising recovery from existing wells.

This paper documents the work done to select the right technology and the right well candidates for a field trial, the design and planning effort that resulted in the first successful application of a Thru-Tubing Gravel Pack (TTGP) in the NW Borneo region.

A well previously producing sand has now been producing sand free for about a year. In addition the paper provides valuable learnings to those wishing to deploy thru-tubing gravel packing technology in existing wells.
A Successful Application of Near-Wellbore Stimulation Using Fluidic-Oscillation Technique in North Africa Oil Field
Authors: Kritsanaphak Kritsana , Tirichine Salah , Kammourieh Muhammad
Published: July 2010

Near-wellbore damage can cause severe reduction in effective permeability and production. A typical solution for near-wellbore damage removal involves wellbore cleanout and squeezing the treatment fluids into the formation through perforation with a conventional jetting-nozzle run on coiled tubing. However, there are numerous old wells in North Africa oil fields that have been completed with a slotted or preperforated liner and require an effective near-wellbore stimulation to remove the damage and restore the near-wellbore permeability and production.

A fluid-oscillation technique created by a fluidic-oscillator (FO) tool was applied successfully in conjunction with stimulation treatments, such as matrix acidizing, salt, and asphaltene treatment. The results from using this tool instead of the conventional jetting tool were significant; the post-stimulation production improved over previous stimulation gains when performed on the same wells. Recently, the fluid-oscillation technique was also applied effectively for near-wellbore stimulation treatments in horizontal wells without requiring matrix squeezing. Results from using this technique have been promising and have simplified the near-wellbore damage treatments. Several wells in this field were treated using this near-wellbore stimulation treatment, resulting in significant production gains. Using the matrix and near-wellbore stimulation in conjunction with the FO tool has become the preferred method to enhance the effectiveness of treatments.

The FO tool creates pressure waves within the wellbore and formation fluids that break up near-wellbore damage to restore and enhance the permeability of the near-wellbore area. As the damage is removed and the original permeability is restored, the pressure waves can penetrate deeper into the formation matrix for more complete damage removal. The direct comparative results from using conventional jetting nozzles and FO tools for several wells in a North Africa oil field are quite evident and are presented in this paper. This technique should help other operators enhance the effectiveness of near-wellbore treatments to achieve similar benefits.
Cementing in HPHT Gas Environment Using a Novel Flexible And Expandable Cement Technology To Withstand Pressure And Temperature Cycles
Authors: Thuwaini J. A.-I. , Emad M. , Ekpe J. , Jaffery M. , Ong D. , Bermudez R. , Taoutaou S. , Ahmad B.
Published: July 2010

Long-term zonal isolation is an important factor to consider while designing cement slurries for deep high-pressure, high-temperature (HPHT) gas wells. Conventional heavyweight cement systems used in the past have often had to sacrifice set cement mechanical properties, such as compressive strength, permeability, and porosity, to provide a stable, mixable, and pumpable slurry design.

Changes in downhole conditions in terms of temperature and pressure can induce sufficient stresses to destroy the integrity of the cement sheath, causing long-term gas migration and sustained annular pressure. Hence, the set cement mechanical properties have to be carefully designed in order to withstand the downhole stresses, especially the ones generated from well testing.

A novel flexible and expanding cement system was chosen for the eighth well of project in Saudi Arabia.
Integration of Static and Dynamic Data to Investigate Interwell Communication: The Case of Module II of Espadarte Field, Campos Basin, Brazil
Authors: da Motta Pires Paulo Roberto , de Lira Eloisa Moreira , Costa Aline Cortizo , de Souza Fabio Carvalho , Benjamin Edivar Narcizo , dos Santos Peter Monteiro
Published: July 2010

This paper describes the investigation of interwell communication in the Module II of Espadarte field, located in the Campos Basin, offshore Brazil. The field started production in January 2007, seven months before water injection. All active wells are equipped with permanent downhole gauges (PDG) to continuously record flowing pressure and temperature.

As history data became available, PDG bottom-hole pressure was extensively analyzed to infer reservoir properties, estimate its pressure and determine well parameters, such as effective permeabilities, skin, and productivity or injectivity indexes. A routine of injector fall-off tests was implemented. The results obtained were combined with the interpretation of producer pressure build-ups after platform shutdowns. Additionally, in order to evaluate their level of connectivity, the reflect of topside events affecting the injectors was also investigated on the flowing pressure of the producers.

A number of seismic attributes was used to correlate reservoir properties with the degree of connectivity between wells inferred from production behavior. Seismic data was processed through the training of an unsupervised neural network identifying clusters or regions of different seismic properties within the reservoir. A material balance model with interference was developed to represent and evaluate the degree of compartmentalization suggested by bottom-hole pressure analysis and seismic interpretation.

All this information together made possible the identification of regions with poor and good communication between injectors and producers. Conclusions have given support to the history matching of a numerical simulator as well as the optimization of water injection rates. This work also highlights the importance of integration of static and dynamic data, represented by seismic attributes and PDG measurements, respectively, to the monitoring of well and reservoir performance.
Deep Tight Gas Zonal Isolation Solution with Novel Flexible and Expandable Cement Technology
Authors: Thuwaini J. A-l , Emad M. , Belousov Y. , Ekpe J. , Taoutaou Salim , Jaffery Maimoon Fayyaz , Ahmad Bilal , Elatrache Bassam
Published: July 2010

The long term zonal isolation is an important factor to be considered while designing cement slurries for deep High Pressure, High Temperature (HPHT) gas well. Conventional heavy weight cement systems which have been used in the past have often had to sacrifice the set cement mechanical properties such as compressive strength, permeability, and porosity, to provide a slurry design which is stable, mixable and pumpable.

Changes in downhole conditions in terms of temperature and pressure can induce sufficient stresses to destroy the integrity of the cement sheath which will cause long term gas migration and sustained annular pressure. Hence, the set cement mechanical properties have to be carefully designed in order to withstand the downhole stresses especially the ones generated during the well testing and fracturing treatments.

This paper will discuss the selection and the Novel Flexible and Expanding cement system and details one well case history of nine wells which is part of the upstream agreement with Saudi.
Condensate Banking Phenomenon Evaluation in Heterogeneous Low Permeability Reservoirs
Authors: Giamminonni D. , Fanello G. , Kfoury M. , Colombo I. , Bonzani A.
Published: July 2010

In low and tight gas formations, condensate banking will form in shortly time after production start-up due to pressure drop below the saturation pressure. Mobility reduction near wellbore area will affect well productivity. The prediction of gas condensate wells production will strongly depend on oil banking evaluation and modeling.

A benchmark radial fine well model has been built using constant petrophysical properties per each layer. Several coarse Cartesian grids have been considered to evaluate discrepancies in terms of production and flowing pressure with respect to the benchmark grid. For a coarser Cartesian grid, it has been deduced that Generalized Pseudo-Pressure (GPP) is a key parameter to avoid well performance over-estimation. An alternative solution consists in defining a local grid refinement (LGR) near wellbore to honour the benchmark solution without using GPP.

In this case study a LGR technique has been used to incorporate future hydraulic fractures for the wells development. A real application case has been considered to extend lessons learned from benchmark to field scale. A proper geological model has been built using a sedimentological model as driver for petrophysical properties distribution.

Two DST have been considered to analyze condensate banking phenomena evaluation in a low and medium permeability matrix. To this purpose, three analytical models have been considered. Thus, to validate a representative analytical model a numeric simulation has been performed. Based on the obtained results, it can be affirmed that the radial composite is the most appropriate analytical model reproducing the phenomenon of gas mobility reduction in the nearest wellbore region.
A New Water-absorbent Resin for Lost Circulation Control
Authors: Lai Xiaolin , Guo Jianhua , Zhou Yaxian , Jiang Xueqing , Li Xudong , Wang Zhonghua
Published: July 2010

Eliminating or controlling lost circulation during drilling or cement operations is a costly and time-consuming process. Water-absorbent resins play an important role in mud loss control for their deformability and water-absorbable and expandable properties. This paper developed a new kind of water-absorbent resin, Double Network Water-absorbent Resin(DNWR), which could be used in deep well or ultra deep well to solve loss problems.

The most difference between DNWR and traditional water-absorbent resins is that DNWR has excellent mechenical properties and good thermal stability; it can be used at the temperature of 150°C for more than 30 days, while the later only could be used below 120°C. The properties and the mechanism of controlling mud loss of DNWR were discussed, after being pumped and squeezed into the formation fracture, DNWR could expand 5–10 times of its original volume, adsorb on the fracture surface, and form a compact sealing layer. Laboratory tests had shown the effectiveness of DNWR in plugging different borehole sizes with a high temperature. The efficiency of this system was enhanced in the laboratory when combined with other inorganic bridge materials which have good thermal stability and optimized particle size distribution.
Improved Permeability Prediction in Heterogeneous Carbonate Formations
Authors: Burrowes Arden , Moss Adam , Sirju Clive , Pritchard Tim
Published: July 2010

Understanding the dominant pore structures is a crucial tool in modelling carbonate reservoirs. Information on pore structure can be obtained through image logs or core data. In situations where there is limited available data such as core analysis, other data sources such as rock cuttings should be explored. Once the pore structure is understood, the appropriate model can be chosen. It has been found that a modified approach to traditional Nuclear Magnetic Resonance (NMR) techniques gives improved accuracy where conventional methods fail. This method results in a better understanding of reservoir behaviour, which should ultimately result in increased hydrocarbon recovery.

For this paper, samples from a highly heterogeneous carbonate database of petrophysical properties are reviewed against established classification methods, such as the Lucia, Choquette and Pray, and newer methods such as the Lonoy classification. Mercury Injection Capillary Pressure (MICP) and NMR data are used to investigate and relate rock types and their dominant pore structures, to measured pore throat and body sizes. Common permeability models are reviewed for each classification and the suitability of each model is assessed and ranked using Pearson's coefficient and a power function. This case study demonstrates where traditional NMR porosity-permeability models are successful and where they are not, and proposes a modified approach to modelling the rock types where traditional methods fail. The practicality of identifying these rock types from logs is discussed and recommendations are made for evaluating heterogeneous carbonate formations. This approach can be applied to heterogeneous carbonate formations where NMR logging runs have been conducted and core samples have been obtained.
Enabling Materials and Corrosion Technologies for Gas Developments
Authors: Wright Eric J.
Published: July 2010

Effective technology application is increasingly important as hydrocarbon resources become more difficult to locate and produce. This approach is illustrated by recent developments in materials and corrosion technology that are applicable throughout the gas production chain. A large proportion of upstream project expenditures are related either to direct procurement costs or fabrication. A wide range of materials is used, although the bulk is represented by specific grades of carbon steel. In addition, the evolving nature of the materials challenges requires the development and specification of materials with improved properties to meet continually higher performance demands.

Qualification testing of these materials, including testing in accurately simulated service conditions coupled with effective specifications and quality assurance is key to achieving the required integrity. Technology developments discussed include: corrosion control to enable full well stream, subsea wet gas pipelines, higher-strength steel for gas transmission pipelines and cryogenic line pipe using nickel-based alloys for subsea LNG transfer. The examples described highlight the important contribution of materials and corrosion technologies to enabling high integrity, cost effective gas field developments.
Evaluation and Qualification of Materials for Subsea Insulation Systems
Authors: Ruschau Gregory R. , Rogers Robert H. , Woodley Sophia A. , Wright Eric J.
Published: July 2010

Thermally insulated subsea production systems are becoming more common in deepwater completions for hydrate or wax control. Premature failures of the insulation materials for these systems have had signification operational impact. Syntactic foams or solid polymer insulation are currently the industry standard for subsea completion equipment. The types of insulation commonly used, their failure modes, and improved methods for selecting and qualifying these insulation systems are presented. For deepwater application, so-called "wet" insulation systems are preferred, because the insulation can be molded directly around the equipment without the need for an outer protective jacket. The insulation is exposed directly to the seawater on the outer surface, with the inner surface exposed to the high temperature operation. The critical parameters in design are the thermal conductivity, insulation thickness, and specific heat capacity. The material parameters of primary concern are resistance to degradation by seawater, high-temperature stability, and physical durability for both deployment and long-term service.
Systematic Elimination and Mitigation of Process Hazards in Project Design
Authors: Kenefake Daryl A. , King Joseph , Victory Donald
Published: July 2010

This paper will describe ExxonMobil Development Company's management system that allows for recognition, evaluation, elimination and/or mitigation of process hazards in upstream facility design. ExxonMobil has a rigorously applied system of design processes and tools through the life-cycle of major projects including concept selection, preliminary design, detailed design, construction and ultimately the operation of the facility. Application of these tools and processes has enabled safe and efficient operations and project execution. Discipline and commitment to "Nobody Gets Hurt" in the design phase of a project leads to facilities that can support safe operations through decades of operations.