bluuebunny/crossref_metadata_2025 huggingface dataset:
Awakening an Old Field – A Case Study of a Refracturing Program in the Greater Green River Basin
Authors: Shaefer M.
Published: December 2007

Restimulation of wells completed in the Frontier Formation, a low-permeability (e.g., 0.01 – 0.05 md) gas sand, has proven to be successful in the Fontenelle Field. The field is located east of the Fontenelle reservoir, on the LaBarge Platform in the western part of the Greater Green River Basin in southwestern Wyoming. In this area the majority of hydrocarbon reserves in the Second Frontier are produced from the massive shoreface sandstones locally known as the Second Bench of the Second Frontier (Kf22b).

To date, Berco Resources, LLC has increased reserves in the Fontenelle Field by restimulating four wells producing from the Frontier Formation with massive hydraulic fracturing treatments. Due to the success of these treatments, another operator in an offset area to the north has also successfully implemented a Frontier refracturing program. This paper summarizes the refracturing program and the success that Berco Resources, LLC has realized. The candidate selection process is examined, as well as operational considerations when restimulating old wells. The stimulation treatments and fluid systems are also investigated. Daily\monthly production data consisting of gas, condensate and water rates along with well head pressures are evaluated for all cases using fractured well type curves, the pseudoradial flow specialty plot (Δp/q vs. log t) and a production simulator comparing actual versus modeled production rates. Finally, the impact of the refracturing treatments on economic return is presented. The success of the refracture treatments has led to a new drilling\completion program in the Fontenelle Field in 2006 by an operator that recently acquired the Berco Resources, LLC properties.
Using Neural Networks for Candidate Selection and Well Performance Prediction in Water-Shutoff Treatments Using Polymer Gels—A Field-Case Study
Authors: Saeedi A. , Camarda K. V. , Liang J. T.
Published: December 2007

Using actual field cases, a neural-network model was developed to identify candidate wells and predict well performance for water shutoff treatments using polymer gels. A feedforward-backpropagation algorithm was used to develop the neural networks. The before and after treatment data for 22 wells treated with polymer gels in the Arbuckle formation in central Kansas were used to train and verify the neural networks.

Polymers and gels have been used extensively in field applications to suppress excess water production and improve oil productivity. Field experience has demonstrated that candidate-well selection is critical to the success of gel-polymer treatments. To date, most candidate-well selections are based on anecdotal screening guidelines, which often results in inconsistent treatment outcomes. With only pretreatment well data as input parameters, the neural networks developed in this work can accurately predict the post-treatment cumulative oil production of the well one month after treatment with an average error of 16%, and the post-treatment cumulative oil production three months after treatment with an average error 10%. This is a dramatic improvement over the current method of using anecdotal screening guidelines for candidate-well selections. This method allows the candidate selection to be based on the accurate predictions of treatment outcomes without having to use complicated reservoir models to simulate the well performance after treatment.
Usari BQI Redevelopment—Paradigm Shift
Authors: Alege F. R. , Brock W. R. , Linscott J. , Olopade B. , Etta C. , Chen L. K.
Published: December 2007

Development of low gravity oil is not very common in the Niger Delta due to the large conventional oil development opportunities available and the belief that secondary recovery methods would be required to achieve comparable recovery levels. The Usari BQI is an example of a relatively heavier crude oil reservoir (API 18-20) in a field of about 35 more conventional reservoirs (API 32-44).

Until recently this water drive reservoir had been only partially developed because of the relatively heavier crude oil, adverse oil-water mobility and a strategy of low producing rates to avoid producing high water cuts in the 70ft oil column. A paradigm shift from studies of analog fields in Nigeria and Western Australia led to a re-development campaign which resulted in a nearly 10-fold increase in production and a significant improvement in reserves in less than 12 months.

Reservoir simulation confirmed the analog data from two fields (Australia and Nigeria) and suggested larger tubing to increase liquid off-take, longer horizontal laterals to contact more reservoir area and denser spacing required to achieve higher recoveries and maximize present value of these relatively more viscous oil reservoirs. In addition, a significant portion of the reserves will be captured only by producing at high water cuts for a long period of time. Performance from the seven wells drilled to date has confirmed the paradigm shift.

Following drilling of three new producers and re-drilling four existing producers with longer horizontal laterals and larger tubing, oil production increased from 5,000 BOPD to nearly 50,000 BOPD and ultimate oil recovery is expected to increase by 20% of STOIIP.

This paradigm shift could be applied in the development and depletion of significant non-conventional oil (low API) reservoirs in the Niger Delta area.
The History and Future of U.S. Oil and Gas
Authors: Li Dacun
Published: December 2007

The United States (US) is the most powerful country in the world, politically, economically, and technologically. In the past twenty years, although the Gross Domestic Product (GDP) of the US has not grown as fast as that of China, the US has sustained its robust energy demand due to the large amount of its GDP. Although rich in natural resources, the US has long been an oil-importing country. In 2002, about 54% of its oil consumption had to be imported, and the gap is still increasing. Along with China, the US was one of the main driving forces for the record-high oil prices in 2005, worsened by Hurricanes Katrina and Rita. In this paper, we derive correlations based on solid oil and gas data reported in the past 20 years and then make predictions up to 2025 by using the correlations. In addition, we compare our predictions with those made by the US Energy Information Administration (EIA). Oil demand predicted by us is comparable with that by EIA under the assumption of low economic growth scenario. The gas demand predicted by us is between the base growth case and high growth case predicted by EIA. Gas consumption in the US will increase by 41% from 2000 to 2025 while oil consumption by 27% during the same period. In 2025, 71% of the oil and 26% of the gas consumed in the US will have to be imported. A lot of oil and gas will have to be imported to meet boosting demand, creating tremendous opportunities in marketing oil and gas to the US.
The Geological Use of Pressure Data: Examples from the Development of the Giant ACG Oil Field, Azerbaijan
Authors: Reynolds A. D.
Published: December 2007

The changes in pressure that occur with depth, stratigraphy, location and time are fundamental to recognising flow units and compartments in oil and gas reservoirs. Such changes can be elucidated via a series of established techniques (pressure, datum pressure and depletion pressure) and cross-plots (pressure-depth and pressure-time). Application of these tools, and a new plot (normalised depletion) to the ACG field in Azerbaijan has revealed: (i) field-wide communication over distances in excess of 30km; (ii) dynamic gradients in both a producing oil leg and an active aquifer; (iii) a clear water-flood response; (iv) strong layering, that was partially recognised at appraisal, fully revealed during primary depletion, and is persisting during water-flood, and (v) variations in transmissibility between layers. These insights are critical in the development of an optimised depletion plan, in monitoring the effects of production and injection, and in assessing the strength of natural pressure support mechanisms. Furthermore, these techniques are likely to have widespread application elsewhere, particularly as pressure data becomes more readily available, via new technology such as MWD formation testers, and distributed temperature sensors.
Maximizing Gas Recovery from Tight Gas Reservoirs in Trawick Field
Authors: Meeks M. H. , Susewind K. D. , Templeman T. L.
Published: December 2007

Trawick field has been rejuvenated through the implementation of new completion strategies and an improved understanding of the reservoirs. Trawick is located in Eastern Texas and is a mature gas field with initial development beginning in 1949. The primary productive intervals are the Travis Peak, Pettit, and James Lime. The Travis Peak and James are both considered to be "tight" gas reservoirs with permeability averaging less than 0.1md in most wells.

By late 2001, cumulative gas production was nearly 1.2 Tscfg. Daily production had fallen to less than 40 MMscfg and was declining at a rate of 12% per year. The Travis Peak and James accounted for more than 75% of daily production at that time. The Pettit was thought to be mostly depleted, so additional production buildup potential was from the James and Travis Peak.

A redevelopment program was initiated in late 2001 to test the feasibility of horizontal completions in the James reservoir. The first few wells performed below expectations. Several mechanical problems were also encountered during drilling and completion operations. An integrated technical effort was initiated to improve the program performance. A high quality 3D seismic survey was acquired and analytic reservoir models were constructed to simulate existing wells. The models and seismic combined to enhance understanding of the reservoir and point out improvements regarding wellbore design, location, and completion techniques that would increase performance of future wells.

The resulting 31 wells (30 horizontal and 1 vertical) were completed in the James by August of 2005 with total daily gas production exceeding 60 MMscfg/D. The drilling program is ongoing and the Travis Peak is now under redevelopment.
Effective Heavy Post-Fracturing Proppant Cleanout with Coiled Tubing: Experimental Study and Field Case History
Authors: Li J. , Bayfield I. , Paton G.
Published: December 2007

Bauxite ceramics are a high strength proppant, which is often used for fracturing stimulation in deep and hot wells. Due to its higher specific gravity (3.5 – 3.6), it is very challenging to design and execute the post-fracturing proppant cleanout with coiled tubing (CT) successfully in the highly deviated large wellbore.

In a sand cleanout with CT the solids are moved by two modes of transport: circulation and wiper trip, in which the localized fluidization is caused by jet turbulence. The jetting turbulence is produced by the down hole wash tool, and as the CT is pulled from the hole it fluidizes and propels the solids in the direction of the wellhead. Some of these solids may stay in suspension and be circulated out of the well depending on the flow velocities, hole geometry and fluid choice. The remainder will tend to fall out of the flow channel downstream from the wash tool. These solids will be continually refluidised by the movement of the wash tool. The speed with which the wash tool can be pulled out of the hole is a complex function of the choice of fluid, flow velocities, hole geometry, hole deviation and the physical properties of the particles. When conditions result in complete removal of the solids, the corresponding maximum value of the CT speed is defined as the optimum wiper trip speed.

In this study, the solids transport test results with bauxite in a full scale flow loop are summarized and four case histories performed on both subsea and land wells are presented. The engineering, implementation and challenge of CT post-fracturing sand cleanout for each individual field case are discussed. The paper also describes how to use a customized down hole switchable wash nozzle and a sophisticated solids transport computer modeling software to optimize the post-fracturing sand cleanout process with 100 % removal efficiency.
New Methods for the Nonequilibrium Initialisation of Reservoir Models With Lateral and Vertical Variations in the Initial Fluid Composition
Authors: Gibson A. , Sørensen H. , Abdou M. , Sener I.
Published: December 2007

New methods have been developed to initialise a compositional model for a giant Middle East reservoir where the initial H2S mol% varies laterally from close to 0 to around 20 and vertically from close to 0 to around 20, being highest at the lower parts of the reservoir.

Conventional initialisation methods assume equilibrium, assigning the same composition to any grid block at a given depth. Two different new method, triangulation and surface-fit, are used to capture observed lateral non-equilibrium variations. Vertical variations in fluid composition are simulated using a gravity segregation model as in the conventional method. The non-equilibrium methods use data on the variation in fluid composition and pressure derived from 18 representative fluid samples collected from wells early in the field history.

The stability of both non-equilibrium methods was initially verified through no-production reservoir simulations.

Simulations were carried out to compare results using the conventional equilibrium method and the new non-equilibrium method. An improved level of detail was verified by monitoring the development of H2S mol% in the produced fluids in three selected groups of wells from regions of the reservoir with different initial levels of H2S mol%.

Field development planning is greatly improved as production predictions now incorporate the regional variations in H2S mol% into the future. Same level of detail can be obtained for other components from the same simulations. As the more sour areas of the field are developed, the new model enables the prediction of H2S mol% and CO2 mol% for the engineering design of new facilities at remote stations and at the main processing plant.
Identification and Characterization of Transition Zones in Tight Carbonates by Downhole Fluid Analysis
Authors: Xian Chenggang , Dawoud Ahmed , Carnegie Andrew , El Mahdi Ahmed , Al Hajeri Salma , Basioni Mahmoud , Raghuraman Bhavani , Fujisawa Go , Mullins Oliver C.
Published: December 2007

In tight carbonate reservoirs, several factors make it difficult to estimate reserves in transition zones. In particular, underestimation of reserves sometimes occurs because the formation oil can be more mobile than expected. The measurement of mobility of the different phases throughout the transition zone, which is affected significantly by complex rock heterogeneity, can only be accomplished by selective flow measurements. To use openhole sampling tools for these flow measurements, it is essential to differentiate between water-base mud (WBM) filtrate and connate water thereby avoiding any negative impact on the oil initially in place (OIIP) calculation and on development decisions. In principle, pressure gradients from traditional open-hole point pressure measurements should help define accurate fluid gradients and contacts. However this procedure is inadequate to identify and characterize the transition zones. Supercharging, capillary effects, changing wettability and saturations, and pressure variations from production and/or injection effects all play a role in complicating interpretation of the pressure measurement data. In addition, gauge effects, depth errors, formation thicknesses and fluid density contrasts yield potentially large uncertainties in interpretation of gradient data.

Downhole pH measurement, embodied within Downhole Fluid Analysis (DFA) procedure, has dramatically improved the situation. Downhole pH measurements utilizing robust pH dyes, the principle behind Litmus paper, have been successfully utilized in differentiating between WBM filtrate and formation water. The downhole fluid analyzers LFA* and CFA* successfully helped determine the level of the anticipated water cut, oil compositions and gravity, and GOR throughout the transition zone allowing a more reliable estimation of hydrocarbon in place and better well placement and production strategies. This process yields considerable cost savings especially by avoiding expensive production tests.
Integration of Surface and Subsurface Models of Commingled Production of Different Reservoir Fluids—Case Study: Gas Condensate Field, Oman
Authors: Al-Marhoon N. , Clark G. , Babajan S.
Published: December 2007

An integration of surface and subsurface models for a deep Gas Condensate field in Oman, containing condensate rich gas in reservoir A (shallower) and dry gas in reservoir B (deeper) is the content of this paper. Production to date was mostly from reservoir A, at which all wells are completed, resulting in the reservoir pressure dropping by 60% in some specific locations from the initial pressure. Furthermore the layered nature of the reservoirs and the varying hydraulic fracturing of the different units, production from the various units differed significantly resulting in significant vertical differential depletion of the reservoir. The field's CGR (Condensate Gas Ratio) has dropped by more than 50% as a consequence of liquid drop out resulting the reservoir A pressure dropping to below the dew point pressure, and the increasing dry gas production from reservoir B through commingled production from some of the wells.

The main challenges in the field is predicting the well performance which is affected by the flow impairment caused by the condensate dropout, the quality of the placed hydraulic fractures in terms of their efficiency and geometry, and completion type, single reservoir or commingled in the two reservoirs (A & B). Also, sealing and non sealing nature of faults play a big role in well performance in the long term. This makes predicting well performance a very complex undertaking.

Integrating Surface and Subsurface models of gas/condensate wells in tight reservoirs with liquid drop-out is still one of the most challenging subjects in reservoir engineering today, especially when it is used as a tool for improving operating philosophy. This integrated project provides an overview of actual reservoir performance in the field over the first 6 years of its production life and the impacts of surface/subsurface integration. For example, high well declines have been observed (upto 50% per annum), the effect of fluid mixture of the rich and dry gas, resulting from the commingled production, the potential cross-flow of the dry gas to the rich gas as was indicated by condensate production and the well capacity, Compression size and timing and operating philosophy. Dynamic models, calibrated by historic production data, are used to assess these effects and to predict future production performance.
Zonal Isolation Modeling and Measurements—Past Myths and Today's Realities
Authors: James Simon , Boukhelifa Linda
Published: December 2007

Over the past ten years, several papers have been published discussing the long-term mechanical durability of the cement sheath. The customary procedure is to use a model to predict potential failure scenarios and to subsequently design a sealant material that will not fail under the expected conditions. The predictive models are either analytical or finite-element models. The analytical models can only be applied to relatively simple situations that require a simplified set of input data. In these cases, the results are consistent with those of finite-element models. More complex situations can be simulated with finite-element models, but the input data requirements are far more severe. Typically in the modeling papers, little information is included on how the input data is obtained. Because of this, several papers have been published that proposed ways to obtain the input data, in particular the mechanical parameters of the set cement. However, because these papers have typically addressed only one or two parameters, the proposed methods are inconsistent. This paper critically reviews the published information; highlights the strengths and weaknesses of the various approaches, and recommends a self-consistent set of measurement methods. The predictions from the given approach have been verified at the field level through evaluation of actual wells.
Allocation Process Modeling for Deepwater Production
Authors: Lerma Perla Gonzales , Simonton Chad , Wadle Tim
Published: December 2007

Development costs have risen drastically as producers have ventured into deepwater operations. This increase in investment level has created a case to tieback subsea wells to hub facilities. The various tiebacks which introduce commingled production with different ownership and royalty rates have significantly increased the complexity of the allocation process, i.e. determining individual well production, portion of sales, etc. Thus, a great deal of effort is spent on determining the best approach and most accurate means of analyzing and allocating the production. On an ongoing basis, the management of the allocations can be a significant effort and many companies have developed custom processes. On top of the allocation complexities, companies are now faced with Sarbanes-Oxley compliance requirements.

BP faced these issues in the management of their complex allocation processes in the Gulf of Mexico (GoM). This presentation discusses the process and trials faced in developing a solution that meets all audit and operational requirements. The final solution, rolled out last year, involved the change of business processes within BP, the development of a new application by P2 Energy Solutions and some BP specific processes developed by several third parties. The benefits thus far have been substantial and include the ability to process each facility in a timely, accurate, auditable and reliable manner.
Geomechanics Insight Into Discrepancies of Core to Image Log Discontinuities and Implications for a Lower Cretaceous Carbonate Field
Authors: YiMing Jiang , Chakravorty Sandeep , Marsden J. Robert , Edwards H. Ewart
Published: December 2007

Renewed interest in fractures and faults in a giant carbonate oilfield offshore Abu Dhabi involves such aspects as their origin, nature, orientation, and impact on productivity of Lower Cretaceous hydrocarbon reservoirs. Studies identified a conundrum with respect to core and image log correlation of discontinuities: fractures and faults, seen on electrical image logs, cannot always be discerned as to whether they are of natural or drilling-induced origin. Cross-reference with cores from the same sections allows such discrepancies to be reconciled: in an example case it was observed that a large number of fractures seen on the images were absent in the cores. This paper describes how geomechanical analyses have been used to address factors leading to the development of drilling-induced features in a borehole and to explain why some fractures on the electrical images were also seen in the cores whilst others were not. This method allows differentiation between natural and drilling-induced fractures when core is absent.

The geomechanical analyses involved using various logs to generate single- and multi-well Mechanical Earth Models (MEMs) describing rock stresses and rock mechanical properties. Using uniaxial compressive strengths (UCS), tensile strengths, rock stresses and estimates of cooling in the boreholes by the circulating drilling fluid, it was demonstrated that mud pressures alone were insufficient to cause the observed artificial fractures. However, thermal effects around the borehole were an additional major contributing factor to many of the observed fractures, and consideration of borehole cooling provided a good match between predicted induced fractures and those seen in the image logs and cores.

Such cooling-induced artificial fractures were found to be common in most of the wells where images were available, mainly located within dense zones. Since fractures in these dense zones play an important role in communication between different reservoirs, the ability to differentiate between actual and apparent fractures seen in image logs is of significant benefit to understanding the reservoirs and their interactions.
A New Technique for Cementing Liners During Total Losses and Gas Influx Using a Foamed Cementing System
Authors: Leuranguer C. , DeMestre P. , AlFadhli A. , Xenakis H.
Published: December 2007

Drilling through weak formations with total losses, while concurrently controlling gas influx by pumping water down the annulus, is a situation often encountered in the main Northern Oman carbonate oilfields. Consequently cementing the intermediate liner and aiming to achieve total annular coverage for zonal isolation becomes a challenge.

This paper describes a technique that has permitted the intermediate liner to be set and fully cemented while experiencing drilling fluid losses and formation flows. Using this technique, the liner packer is set before cementing, thus isolating the gas influx and removing the need to pump in the annulus during the cementation. Then by cementing using a foamed spacer and foamed cement in stages, the fluids can be effectively diverted up the annulus across the loss zones resulting in zonal isolation. For better control of the volumes, and to be able to react to a possible early increase in pressure, the inner-string liner method is used. This cement procedure has been employed on several wells and the cement bond log (CBL) results are very encouraging. Prior to employing this method, cement was only evident around the liner shoe joint. With this new method the total liner length has shown cement coverage from 80-100% with the top of cement (TOC) approaching the previous shoe. In addition this technique has resulted in economic gains by eliminating stage tools and annular packers.

The drilling challenges of these fractured wells, the cementing requirements, the design notion of the foamed fluids, the operational execution, and the observed CBL results are all discussed. The value added by using this technique is also demonstrated.
Challenges, Lessons Learned, and Successful Implementations of Multilateral Completion Technology Offshore Abu Dhabi
Authors: Kikuchi Shuichi , Fada'q Abdulla S.
Published: December 2007

ZADCO with the supports from shareholders and the cooperation of ADMA-OPCO has successfully completed the final design of MLC (Multi-Lateral Completion) system for Reservoirs A and B through MLTBS (Multi Lateral Tie Back System) project in a re-entry well, Well T-2 in Upper Zakum field. Well - T2 was re-completed as dual lateral/dual producer from Reservoirs A and B utilizing a RDS (Re-Entry Drilling System) Ver.2 and a DBD (Dual Bore Deflector) with a latch coupling of orientation device in the 7" liner hanger assembly for each lateral access.

According to TAML (Technology Advancement Multi-Lateral) level specification, the final MLC is categorized as TAML Level-4 E-2-PN-D/4-TR-SEP (Level-4, existing well application, two junctions, producer with natural lift, dual completion, tubing re-entry, separated flow). Multi-Lateral liner hanger system, i.e., accommodating a latch coupling in 7" liner hanger assembly to have a certain access to the upper lateral, was the first success application in the world.

The teamwork and integrated approach for the trial planning and implementation as well as lessons learned from a pre- design trial (TAML Level-4 E-2-PN-D/4-TR-SEP using straddle assembly) for Well T-1 completed in year 2000 have led to reaching the final goal of MLC in Well T-2, which provides ZADCO with following reservoir benefits -:

– Independent coiled tubing access to the upper and lower lateral of reservoir A and B through dual completion to perform effective stimulation and reservoir monitoring. – Full bore access to each lateral immediately after pulling out the completion, which is an additional feature to the pre-design of MLC for Well T-1. – Allow conducting selective water shut-off to cope with water breakthrough into the upper cased lateral and extending well life by drilling a secondary lateral from a window joint installed in the upper cased lateral.

Moreover, another MLC trial using a mechanical selective through tubing re-entry equipment has been also successfully implemented in a quadrant multi-lateral well of RL-2 in 2005 after experiencing an operational failure with the similar MLC design tried in Well RL-1 during 2001.

The successful trial implementations have proved that the MLC system will be able to apply for any new/re-entry well for ZADCO reservoirs, provide new methods for reservoir management, and allow creating new completion strategy for ZADCO field development.

This paper will cover MLC strategy created for MLTBS project, lessons learned through the successes and failures of the MLC trials, and additional challenges planned for future.
The Impact of Chloride Contamination From Leaking Heat Exchanger Tubes on Plant Materials of Construction
Authors: El-Roubi E. Y. , Kermani B. , Nasif M. Selim
Published: December 2007

Heat exchangers using sea water for cooling play an important part in the petrochemical processes, but can also cause damage to other components if the tubes fail. Chloride leaks from heat exchangers in the acid gas removal unit of the ADGAS liquified natural gas (LNG) facilities on Das Island, were detected. This leak posed a potential risk of fast rate chloride stress corrosion cracking (Cl−SCC) on stainless steels (300 series) used in the plant. To examine the effects of Cl− contamination, elaborate analysis of process flow diagrams (PFDs), materials of construction and operating cnditions was carried out. For Cl−SCC to take place a combination of environmental, metallurgical and mechanical factors must prevail.

The investigation led to a number of key conclusions which were adopted and which have contributed to maintaining the integrity and safe operation of the plant. A set of corrosion mechanisms was identified in this plant which can affect its integrity. Finally, a risk rating was developed for each operating vessel/condenser tube bundle, which provided a priority list of areas with high to low potential risk.
The Role of Geomechanics at Early Stages of Field Development: A Case Study
Authors: Gomes Jorge S. , Ribeiro Maria , Neghaban Shahin , Dabbour Yousef , Bahmaish Jamal , Zaborowski Georges
Published: December 2007

This paper presents the methodologies and approaches adopted by the Asset Team to integrate geomechanics at the early stages of a field development. The reservoir is a tight carbonate formation, with low structural relief and is offset by major strike-slip faults. The development plan called for a line drive pattern of horizontal producers and injectors (4000 ft open-hole completions), targeting layers with different petrophysical and geomechanical properties. Water-Alternating-Gas (WAG) was selected as the main recovery process. The main concerns at the early stage of field development were the following: 1) What is the best orientation for the horizontal wells ?; 2) Will there be any thermally induced fracturing during injection ?; 3) What would be the role of the existing faults within the development area ?; Would any fault reactivation be expected ?; 4) What would be the impact of joints/faults as permeability enhancements due to pressure and/or temperature gradients. 5) Is there any stress dependency of porosity and permeability ? All these questions were addressed before planning the horizontal wells by conducting a judicious and fit-for-purpose geomechanical study. The aim of this paper is to summarize the geomechanical workflows conducted in the Team prior to the drilling campaign to assess the best orientation for the horizontal wells.
Miscible Gas Injection Piloting and Modeling in a Giant Carbonate Reservoir
Authors: Haajizadeh Masoud , Hafez Hafez H. , Al Hassan Rasheed , AlKatheeri Abdulla Bakheet , Ghozali Mohamed N. , Kenawy Madher
Published: December 2007

The subject reservoir is a heterogeneous carbonate formation in a giant field located in the onshore area of Abu Dhabi. The reservoir can be divided into a higher permeability upper zone and a lower permeability lower zone, with comparable initial oil in place. The reservoir is currently under peripheral water injection. Because of a high contrast in permeability, the injected water has advanced in the upper zone much faster, resulting in watered out wells in this zone. The water movement in the lower zone is by inverse coning from the upper zone.

A gas injection pilot was initiated in 2002 to evaluate the benefit of miscible gas injection as a secondary process in the lower zone and a tertiary process in the water-flooded upper zone. This paper covers the pilot description and the corresponding compositional simulation studies.

A comprehensive pilot monitoring program was designed to acquire key performance data, including, time-lapse saturation logs, PLT, wellhead and bottom-hole pressure, production tests, gas tracers, and well head samples. The compositional simulation studies comprise one-dimensional models for examining the displacement process, a fine-grid pilot model for analyzing and optimizing pilot performance, and a full field model for assessing potential benefits associated with field-scale gas injection options.

The pilot has been in operation for over three years and has met all the initially set objectives. The paper discusses the observation results and compares them with simulation predictions. We show that model predictions satisfactorily match field observations. In particular, both model results and time-lapse saturation logs indicate that the gas, which is injected from a horizontal well in the bottom of the lower zone, quickly moves to the more permeable upper zone, resulting in poor sweep of the lower zone.

The results of the monitoring program are used to optimize the pilot performance and to calibrate the dynamic reservoir simulation model for more reliable predictions.
Uncertainty Analysis of a Giant Oil Field in the Middle East Using Surrogate Reservoir Model
Authors: Mohaghegh Shahab D. , Hafez Hafez , Gaskari Razi , Haajizadeh Masoud , Kenawy Maher
Published: December 2007

Simulation models are routinely used as a powerful tool for reservoir management. The underlying static models are the result of integrated efforts that usually includes the latest geophysical, geological and petrophysical measurements and interpretations. As such, these models carry an inherent degree of uncertainty. Typical uncertainty analysis techniques require many realizations and runs of the reservoir simulation model. In this day and age, as reservoir models are getting larger and more complicated, making hundreds or sometimes thousands of simulation runs can put considerable strain on the resources of an asset team, and most of the times are simply impractical. Analysis of these uncertainties and their effects on well performance using a new and efficient technique is the subject of this paper. The analysis has been performed on a giant oil field in the Middle East using a surrogate reservoir model.

The surrogate reservoir model that runs and provides results in real-time is developed to mimic the capabilities of a full field simulation model that includes one million grid blocks and takes 10 hours to run using a cluster of twelve 3.2 GHz CPUs. In order to effectively demonstrate the robustness of Surrogate Reservoir Models and their capabilities as tools that can be used for uncertainty analysis, one must demonstrate that SRMs are competent in providing reasonably accurate results for multiple realizations of the reservoir being studied. In order to demonstrate such robustness and their predictive capabilities as well as their limitations, this paper will examine the performance of the surrogate reservoir models on different geologic realizations of the static model.
Production Well Testing Optimization Using Multiphase Flow Meters (MPFM)
Authors: Hassan M. Metwalli , Bekkoucha M. , Abukhader M.
Published: December 2007

Production testing using portable Multiphase Flow Meters (MPFM) was implemented in ADCO Field "B" with objectives to quantify the water and gas production, evaluate the performance of slugging/intermittent wells for procurement actions, evaluate the production test data measured by the conventional test separators and improve the testing duration and strategy. The program included in addition a set of elements to qualify the multiphase meters results before use and considered parallel testing with conventional separators to allow fair comparison of results.

More than 50 wells were tested during this campaign. All these wells were selected carefully to represent anomalies that need to be investigated for possible proactive actions. Some of these wells were tested more than once to qualify and validate the production test results by the MPFM. Production test results were carefully analized and compared with the results of test separators for fair evaluation and interpretation of well's behaviour. The comparison indicated that the multiphase meter results were relevant and accurate.

In conclusions the water cut measured by MPFM was almost three times more than those measured by test separators. This ratio is matched well with the actual field water volumes. The GOR measurements were varying from one well to another but majority of wells showed more gas production by the phase tester compared with test separators specially for the low potential, unsteady wells. In terms of oil production rate, the difference between the phase testers and test separators was marginal in high potential wells and between 20-40% higher by MPFM in low potential wells. These findings helped in optimizing reconciliation and allocation of the water and gas production. In addition to the above findings, phase testers helped in reservoir management decisions and optimization of testing duration and frequancy per well, testing remote wells, slugging/intermittent wells due to system back pressure, testing wells located on platforms not equipped with testing facilities, easy mobility of the phase meters between different locations, replacement of portable test separators and cost optimization.

This paper presents the experience gained using a mobile multiphase well testing unit for production testing. The challenges presented by the nature of these operations and the requirements for successful well tests are reviewed. The importance of well testing experience and multiphase flow metering expertise is highlighted. The paper also explains the unique benefits of the multiphase well test data in identifying and evaluating various well performance anomalies and how the measurements are used to monitor well production over time.
The Application of Air and Air/Foam Drilling Technology in Tabnak Gas Field, Southern Iran
Authors: Chen Guang , Chen Xingyuan , Liu Desheng , Cheng Xiaonian , Liu Chuansheng , Wang Dekun
Published: December 2007

Tabnak gas field is located in the Fars province, Southern Iran. Severe lost circulation problem were encountered while drilling the long interval of large size hole in the highly fractured and porous carbonate formations. To resolve the severe lost circulation problem, Air and air/foam drilling technology was chosen as a main means to drill through the top intervals and an air/foam drilling program was worked out. The field application proved that air and air/foam drilling could resolve the severe lost circulation problem in the highly fractured and porous carbonate formations with very low formation pressure and speed up the penetration rate significantly. The drilling cost also reduced dramatically.
Installation of Online Vessel Desander Manifolds
Authors: Jasmani M. S. , Geronimo E. C. , Chan L.
Published: December 2007

Sand production in the brown field is a common phenomenon. If left uncontrolled, sand can erode the line pipes, valves, instruments and ultimately causes unplanned production shutdown. Even if the sand production rate is relatively low, sand can accumulate inside the production separators after a period of production. This sand build-up is reducing vessel volume for effective separation of oil, gas and water.

Dulang-B Platform, which is located at South China Sea and operated by Petronas Carigali Sdn Bhd (PCSB), has recorded severe sand accumulation on its production separators as observed during vessel inspection. This resulted in unnecessary production downtime to allow for cleaning of the vessel and removal of sand.

To mitigate the problem, two units of Online Vessel Desander (OVD) manifolds were installed inside one of the HP Production Separator of the platform on trial basis. Each manifold consists of a series of pipe work connected to the desander devices. The device uses hydrocyclone principle to elevate and transport sand from the base of the vessel out to a filter tank without the need to isolate the process stream. This pilot installation of the manifolds was the first in PCSB and Malaysia.

Over a month period, a total of 809 litres of sand have been removed from the separator vessel with no production downtime. Operations personnel reported improvements on level interface of the separator and less erosion on the downstream equipment, particularly level control valves. The annual shutdown previously required for sand cleaning was also eliminated resulting in monetary savings.

Thus, the OVD manifolds are an effective technology to replace conventional sand jetting for sand removal from production separators.
Assisted Interpretation of Fiber-Optic Data for Smart-Well Completions
Authors: Lee Jim H.
Published: December 2007

New methods have been advanced to process, manipulate, and utilize real-time data from permanent downhole monitoring (PDM) systems such as fiber optic (F-O) pressure, temperature, and flow sensors. These interpretative methods are centered upon detailed computational fluid dynamics (CFD) simulations of the wellbore and surrounding near-wellbore region. In addition to facilitating the solution of geometrically complex flow dependencies, the CFD approach accounts for the highly coupled chemical physics inherent in multi-phase systems, particularly gas compressibility effects that impact wellbore hydraulics and heat transfer which, in turn, govern the flow, pressure, and thermal profiles in the wellbore. In the near-wellbore region, true reservoir permeabilities and porosities are honored and used to populate the CFD model. By running the model for different anticipated production scenarios, a series of production "type curve" analogues are generated that can be used to "predict" the time-dependent flow, pressure, and thermal profiles recorded by a PDM, thereby assisting interpretation of the data.
Opportunities and Challenges for Enhanced Recovery in the Middle East
Authors: Wilkinson J. R. , Teletzke G. F. , King K. C.
Published: December 2007

A worldwide look at long-term trends reveals that new discoveries of conventional oil fields are declining while demand for oil is estimated to increase approximately 1.5% per year from the current levels of approximately 85 million bopd. The Middle East will provide a key role in future long term supply of oil to meet world demand. A portion of the increased demand will be met by increasing supplies from non-conventional deposits but the majority will need to come from improved rates and recovery in conventional oil fields. Industry experience and performance to date indicates that while considerable opportunities exist, there will also be fundamental challenges facing our ability to increase light oil recovery from complex carbonate reservoirs in the Middle East. For both host governments and industry partners, increased attention on fundamental parameters driving increased field offtake rates and recovery factors will yield long term dividends. This paper will discuss both basic technical parameters that need to be addressed and the improved/enhanced oil recovery (IOR/EOR) technologies that can be deployed (or developed) to meet this challenge. It also covers the pros and cons of various types of enhanced oil recovery injection fluids. Attributes of enhanced recovery fiscal regimes that are mutually beneficial to both host governments and the international partners will also be summarized. Successful implementation of projects will come from partnerships that capture unique strengths and abilities of all involved parties to increase Middle East production and help meet anticipated world demand.
From Concept to Pilot to Full-Field Implementation: A New EOR Process for the Prudhoe Bay Field
Authors: McGuire P. L. , Carini F. H. , Ambrose J. G. , Yancey A. N. , Panda M. N.
Published: December 2007

The uppermost 200 ft of the main pay interval at Prudhoe Bay is a moderate permeability, high net-to-gross fluvial sandstone which contains a number of thin, discontinuous shales. Most of this interval is being produced by waterflood and miscible gas WAG, but the updip third of Zone 4 has been produced by gravity drainage since 1977 and is very mature.

Fullfield models and material balance estimates indicated good recovery in the updip area. One Zone 4 core was taken in the gravity drainage area and one was taken in the waterflood/WAG area. Both cores were history matched with a reservoir simulator to determine the ultimate recovery potential of the process currently being employed. Detailed simulations indicated that the gravity drainage process was leaving high oil saturations behind the gas front which could not be produced economically because of excessive gas-oil ratios (GORs). Both water injection and miscible gas injection mobilized large volumes of oil and dramatically reduced the GOR.

The Updip Zone 4 Injection Project (UZI) is designed to mobilize and capture remaining oil trapped above the current gas-oil contact. In the updip area, both water and miscible injectant (MI) have been injected in Zone 4 while maintaining gravity drainage in the lower intervals (Zones 2 and 3). UZI patterns employ MI in a unique, highly efficient, single-slug oil swelling process rather than as a tertiary WAG. UZI injection has mobilized large volumes of oil and dramatically reduced GORs. The 14-01A pilot has produced roughly 2,000 BOPD of additional oil for the last 5 years from MI injection into a previously gassed-out producer. Total incremental oil from the MI pilot is approximately 3.5 MMBO.

The 1-11 water injection pilot is another success, with five of the eight offset wells producing an incremental 960 BOPD and 35 MMscf/D less gas. This major reduction in gas production has allowed increased production of about 700 BOPD from other Prudhoe Bay wells. A tracer program in the waterflood pilot has verified water containment within Zone 4. Based on this success, the Prudhoe Bay Unit has been expanding the UZI Project. Ten UZI patterns are already developed in the Eileen West End area. In the mainfield area, four patterns are currently on-line with another four patterns approved.

This paper briefly reviews the core analysis data and the reservoir simulation history match of the two Zone 4 cores and the process comparison studies. Production data from the updip waterflood and miscible gas flood pilot tests is presented, as is the performance of the early UZI patterns.