bluuebunny/crossref_metadata_2025 huggingface dataset:
Challenges for Coiled Tubing in Horizontal Well Intervention
Authors: Rohilla Pulkita , Shukla Himanshu
Published: February 2011

Most coiled tubing (CT) interventions are performed in a Rigless environment. Infact, this is one of the important drivers for the widespread acceptance and continued growth of the technique for well servicing. Now a days in most of the reservoirs with high water-cut wells are drilled horizontally. But its maintenance and work over jobs are challenging and needs the most advanced and precise technology. As a result CT units are employed to do the interventions in horizontal wells. But it faces the following problems during its operation Fill material can rapidly accumulate on the low side of the wellbore during production and during conventional removal operations. In some cases, the fluid velocity can carry fill along horizontal sections, but cannot lift it through the build angle into the vertical wellbore. Gravity causes the particles to accumulate and slide down the low side of the wellbore, especially at inclinations of 300 to 600. Once the fill has settled, it is difficult to re-establish particle transport. Turbulent flow significantly improves hole cleaning in a horizontal wellbore. However, in many cases, turbulent flow is not possible, due to the flow and pressure restrictions imposed by the CT work string, or the relative size of the completion tubular.

This paper describes the solutions to the above mentioned problems along with the description of the new tool used. which leads to the better functioning of the unit and stability of borehole.
Rigorous Water Chemistry Modelling in Reservoir Simulations for Waterflood and EOR Studies
Authors: Wei Lingli
Published: February 2011

Many waterflood projects now experience significant amount of water cut, with more water than hydrocarbon flowing between the injectors and producers. In addition to the impact on water viscosity and density from using different injection water sources during a field’s life, water chemistry itself may impact oil recovery as demonstrated by recent research on low salinity water injection schemes. It is also known that water chemistry has profound impact on various chemical EOR processes. Moreover, the effectiveness and viability of such EOR schemes is strongly dependent on reservoir brine and injection water compositions. In particular, the presence of divalent cations such as Ca+2 and Mg+2 has a significant adverse effect for chemical EORs. Utilising new developments in reservoir simulation, this paper outlines a method to account rigorously for water chemistry with only a small incremental computational cost compared to the same simulation model without geochemical reactions. The new modelling capability considers chemical reactions triggered by injection water and/or injected reactive gases such as CO2 and H2S, including mineral dissolution and precipitation, cation exchange and surface complexation.

For waterflood performance assessment, this paper demonstrates that rigorous modelling of water chemistry can significantly impact simulation results. In addition, interpretation of saturation logs requires inputs about brine composition. Thus, the new modelling capability makes possible a more optimum evaluation of petrophysical logs for well intervals where injection water invasion is suspected. By modelling transport of individual species in the aqueous phase from injector to producers, reservoir characterization can also be improved through the use of these natural tracers, provided the compositions of the actual produced water are used in the history matching. The simulated water compositions in producers can also be used by production chemists to assess scaling and corrosion risks. For CO2 EOR studies, we illustrate chemical changes inside a reservoir and in the produced water before and after CO2 breakthrough, and discuss geochemical monitoring as a potential surveillance tool. Alkaline flood induced water chemical changes and calcite precipitation is presented to illustrate applicability for chemical EOR with the new simulation capability.
Permanent Downhole Production Monitoring & Well-testing of Commingled Production Reservoirs
Authors: Kremenetskiy M. I. , Ipatov A. I. , Gorodnov A. V. , Chernoglazov V. N.
Published: February 2011

Commingling differentiated control providing is actual problem for multi-layer oil fields in the Russian Federation. There are multiple economic benefits of commingling reserves that can provide very large increases in incremental project NPV for all types of oil and gas field developments. The benefits of commingling production from separate reservoirs are: ability to produce hydrocarbon from multiple reservoirs which may not be economic to produce on their ownfewer wells, less infrastructure - lower capital expenselower operating expensesless environmental impact, fewer locationsa sustained production plateau

The regulations for the commingling of down-hole production are typically set by government agencies responsible for oil and gas developments. There are very few areas of the world that permit commingled flow from different reservoir intervals without approved means of control, testing of segregation, and flow estimation and allocation. Russian government regulators limit commingling by continuous monitoring stringent requirement for each reservoir. This opportunity allows a license holder to both manage and control of oil field development and water oil displacement processes.

Separate monitoring and development management task has been technically solved nowadays at pilot level by a number of national oil companies. For instance, GazProm Neft specialists tested the technical side of the problem and its possible solutions at the Yuzhno-Priobskoe oil field in 2009. The work has been continuing in 2010. [1].
Modeling of Acid Treatment in Oil Reservoirs
Authors: Volnov . A. , Kanevskaya . D.
Published: February 2011

The mathematical model of two-phase displacement of oil by an acid aqueous solution in the neighborhood of a well and a hydraulic fracture is created. It takes into account the kinetics of acid dissolution of a carbonate rock. The proposed model allows us to investigate the penetration of the active admixture and the changing of the reservoir characteristics during the solution injection and after well shut-in for reaction.

The effect of well acidizing and acid fracturing are estimated. It is shown that neglecting the two-phase nature of the flow leads to the underestimation of the treatment effect. At given process parameters the needed length of the shut-in period for reaction and dimensions of the acid penetration zone are estimated.

The control of such parameters as the injection rate and the chemical reaction rate makes possible to reach the maximum treatment effect at the given solution volume. Calculations showed that in the case of the acid fracturing the significant slowing of the reaction rate may lead to large leakage of unreacted acid into the reservoir, extending the penetration zone, but also reducing the effects near the fracture and thus worsening the result of treatment.

The created model was applied to numerical calculations for real cases. Field and calculated data are in good agreement.
Dynamic SAGD Well Flow Control Simulation
Authors: Stone T. W. , Guyaguler B. , Bailey W. J. , Damas C. E. , Naccache P. F. , Morton A.
Published: February 2011

An investigation is presented on the use of Flow Control Valves (ICVs, FCVs) to control steam placement in the early stages of a Steam Assisted Gravity Drainage (SAGD) process. The two parts of this process that are examined in this paper are the steam circulation preheating period and the early stages up to one year of injection/production in which the steam chamber is beginning to form. Steam injection and production in this and other thermal processes can be difficult to control because steam has a high mobility ratio and tends to establish flow paths that may be difficult to break once established. This is especially pronounced in heterogeneous reservoirs. Two SAGD case studies have been designed that accurately model the initial preheating period in which both wells circulate steam through an inner tubing and outer annulus in order to conductively and, to a lesser extent convectively, heat the region around the well pair in order to establish communication. After this initial circulation period, the wells switch to injection and production. Both cases have the same base configuration but differ in the degree of reservoir heterogeneity. In the injection well, ICV devices are placed to control steam/water flow through the outer screens. In the producer, FCV valves are used to flatten the production profile along the well. Two methods are examined to change valve apertures. One uses proportional-integral-derivative (PID) controllers while the second applies an optimization algorithm directly on each individual connection productivity index. A preliminary investigation is presented here into using feedback controllers and optimization with instantaneous reservoir parameters to improve a SAGD process in the presence of reservoir heterogeneity.
Adaptive Technology for Waterflood Management
Authors: Kostrigin I.V. , Khatmullin I.F. , Khatmullina E.I.
Published: February 2011

Reliable estimation of the deposit energy/volume dynamics is the key to ad-hoc decision-making in managing waterflooding operations.

The paper describes the key elements of a single-layer waterflooding proxy-model. The pressure and saturation field calculations are performed by means of a two-phase streamline simulator developed by the authors.

The proxy model simulation includes an iterative adaptive matching procedure for the saturation/productivity data field, the actual bottom-hole/reservoir pressure data, and the actual injection/production rates. The fitness of inferred areal distribution of the reservoir parameters and the current recovery is by matching the calculated dynamic reservoir pressures and rate values with the available production history and well test data.
Systematic Approach Ensuring Asset Integrity, Equipment Reliability and Process Safety
Authors: Derevyakin . M.
Published: February 2011

Today for oil industry can be characterized as “the time of problems”, and not in terms of the global financial crisis and slump in oil prices but in terms of equipment age. The issue of outdated equipment stock is acute for Russia and the whole world as well. What should be done with it and how should it be used safely? How should technogenic disasters and accidents be avoided? What is the way to do it effectively so as to be sure that facilities are safe and thus do not endanger lives of people and do not entail severe financial losses?

Oil companies, carrying out equipment maintenance, believe that all problems are solved; however, actual state of play proves it not true.

To settle the said issues a common approach has been developed, which is aimed at ensuring of safety of industrial facilities and, simultaneously, at optimization of preparation, planning and performance of work for equipment maintenance. This approach is based on clear understanding of risks related to each particular equipment type, establishment of equipment performance/integrity criteria and implementation of the systems for monitoring of compliance with these criteria, which also influences equipment integrity.

Implementation of the new process of preparation, planning and performance of work enables to ensure equipment reliability and integrity due to the possibility of timely performance of more critical maintenance work as well as enables to improve efficiency and reduce expenditures on this kind of work.

The author of this work shares his experience and explains the need for integration of HSE systems and processes, maintenance and personnel development processes, in order to assure equipment integrity and safety of operations.
A Case Study of Smart Well Deployment for Arctic Offshore Subsea Field Development
Authors: Khrulenko A. A. , Zolotukhin A. B.
Published: February 2011

This work deals with the efficiency of smart (or intelligent) wells, i.e. wells equipped with inflow control valves (ICV) and bottomhole pressure and temperature sensors in a moderate in size oil field, located on the Arctic shelf and developed using subsea technologies.

The assessment was performed by comparing results of calculations of various stochastically generated geostatistical models of a hypothetical field using two development options - with and without smart completion. The latter can be considered as an alternative to traditional water shutoff works. The ECLIPSE simulator supplemented with the software add-in has been used for calculations. This add-in enabled us to perform reactive control of two-position (on/off) ICV during the model computations.

The field model is based on the following principles:

Elastic water drive, high stored elastic energy in the water-bearing area, enabling to develop the field without the reservoir pressure support system; Underexplored reservoir properties, expressed in several equally probable stochastic realizations of the porosity and permeability distributions; Uncertainty of fluids' properties and of the reservoir′s type (wettability mode), realized using various options of relative phase permeabilities (RPP).

For each realization of the reservoir model (combination of phase permeabilities and petrophysical parameters) two options of the field development were calculated:

Uncontrolled commingled production from two reservoirs using conventional wells; Commingled development of oil reservoirs with production control using two-position inflow control valves;

In the flow models, the following limitations specific for subsea production were realized:

▪ Wells shall flow with wellhead pressures higher than specified minimum allowed pressures; this makes possible the multiphase flow through the subsea pipelines to the nearest offshore platform. When the wellhead pressure drops below the specified limit, the well shall be decommissioned. ▪ For the option B, the inflow from individual perforation intervals shall be adjusted in order to extend the period of well flowing and thus, to increase oil production.

Comparison of calculated production profiles for options A and B for the each model realization showed a significant economic benefits due to ICV usage. Generally, results of the work demonstrate that smart wells help to improve the economic and technological parameters of the project and to reduce risks of its realization due to uncertainties.
Influence of the Multi-Layered Reservoir on the Production Dynamics of the Gas Condensate Well During Multi Rate Testing
Authors: Shandrygin A. , Rudenko D. , Kuzmichev D.
Published: February 2011

The paper considers the problem of gas condensate production from a multilayered reservoir. Sufficient influence of the individual layer properties was demonstrated by the analysis of a 2-layer formation where synthetic properties were varied over a wide range. Analysis of a field case supplements the results. The study demonstrates a sensitivity of the inflow performance relationship (IPR) curve to the formation layer parameters, and authors propose a model for IPR curve analysis for estimation of the parameters and evaluate it using synthetic IPR curves.
Multi-Phase Flow Meters for Well Testing – Field Experiences in an Offshore Field, Abu Dhabi
Authors: Santhanam Kalakad S. , Al-Marri Faisal M. , Attas Ali , Al-Zarooni Nabil , Khan Ayyaz , Ehmaid Bassam , Kumar Kotha Ravi , Basak Gautam , Ladmia Abdelhak
Published: February 2011

This paper presents the field trial testing of three brands of Multi-Phase Flow Meters (MPFM) in a matured offshore field, being operated by ADMA-OPCO in Abu Dhabi. The purpose of the MPFM installation was to enhance the well testing in order to efficiently manage the reservoirs and production. ‘Trial Tests’ were conducted successfully with simultaneous measurements through Test Separator (TS) mounted on boat Test Vessel (TV) for verification and performance evaluation. All 3 MPFMs were permanently installed on 3 different Towers to acquire independent operational experiences and assess vendor’s technical and maintenance supports. The paper includes experiences & performances of MPFMs, which led to the field implementations that are currently in progress.
Completion Optimization in the Lower Huron Shale in Kentucky
Authors: Wozniak Gregory , Vactor R. Taylor , Hina Derek
Published: February 2011

EQT Production has been an active driller in the Lower Huron Shale in the Appalachian basin for nearly 100 years and has close to 5000 producing vertical wells in Kentucky alone. In 2006, EQT began drilling horizontal wells and has drilled over 400 Lower Huron Shale and over 100 Cleveland Shale wells in Kentucky through mid-2010. EQT has experimented with various completion designs and fracture methods in order to maximize production from these wells. EQT traditionally has performed both foamed nitrogen and nitrogen gas hydraulic fracture treatments, with the selection between the two dependent on reservoir pressure data taken from vertical offset wells drilled and completed in past decades. EQT also performed 33 hybrid (ultra-high quality foam) treatments on Lower Huron wells and compared their production against the production from their offsets. EQT studied the effect that frac stage length has on well production. The method in which the open-hole packers were set was also analyzed and found to be influential in well performance. From these studies, EQT has identified ways to improve well performance for a minimal cost by altering the completion design and has implemented these design changes in their completion programs.
Integrated Discipline Approach to Conquer Asphaltene Challenges in On-Shore Abu Dhabi Oil Fields
Authors: Grutters Mark , Ramanathan Karthik , Naafs Dennis , Clarke Ed , Huo Zhongxin , Abdallah Dalia , Zwolle Simon , Stankiewicz Artur
Published: February 2011

This paper describes an integrated discipline approach to investigate and mitigate asphaltene challenges in an onshore Abu Dhabi oil field. This large carbonate field produces from three reservoirs with substantial lateral variation of fluid properties. Several wells in the northeastern part of the field producing from one of the three oil reservoirs suffer from asphaltene deposition in the wellbore. A multidisciplinary team of experts from Shell and ADCO worked closely together to evaluate the natural controls on asphaltene stability in this oilfield and to predict whether deposition in other areas of the field may be expected in the future. In addition, a robust inhibition and mitigation strategy has been developed.

A thorough review of production and well intervention data, combined with detailed analysis of field deposits confirmed that wellbore deposition was due to asphaltenes in approximately one third of all the affected wells. In order to understand the variability in fluid properties, a wellhead sampling and fluid analysis campaign was carried out (39 wells distributed across the field). Analyses of basic fluid properties such as API, S%, Ni, V, SARA supported by more sophisticated geochemical characterization data of the reservoir fluids clearly demonstrated that the lateral variability in fluid properties from NE to SW is attributed to two processes: (1) geological mixing of fluids from different sources into the reservoir, and (2) maturity variation of fluids form the same source in the reservoir. Furthermore, stock tank oil asphaltene stability tests clearly indicated that fluids from the NE have a high tendency to be unstable with respect to asphaltene precipitation, and fluids from the SW of the field are stable. These results are in agreement with field observations. The confirmation of the field data with simple laboratory tests allowed for the development of empirical correlations between certain fluids properties and the risk of asphaltene precipitation and deposition. Based on this it was concluded that deposition is not expected to expand to the SW part of the field during the production lifespan. Moreover, a cluster of wells has been identified in the NE were deposition has not occurred to date but with a high propensity for deposition if production conditions will change. For these wells and the ones with confirmed asphaltene deposition problems additional live-oil testing, thermodynamic modeling as well as a surveillance plan have been suggested, which will further improve the correlations and help to identify challenges ahead of actual deposition.
Field/Well Integrity Issues, Well Abandonment Planning and Workover Operations on an Inadequately Abandoned Well: Peace River Alberta Case Study
Authors: Diller Chris
Published: February 2011

Maintaining well integrity for field lifecycle operations is a major factor that must be taken into account in the planning and execution of all Well Engineering activities. Some legacy wells are not properly abandoned to prevent the contamination of secondary reservoirs and/or groundwater from other producing hydrocarbons, or from emerging carbon capture and acid gas storage projects being planned by both oil and gas operators and government research groups. If these wells are not identified and properly abandoned, there is a high risk of negative impact to the environment, operator reputation, and the economics of field operations.

This case study will examine the complex re-entry and re-abandonment of a well in the Peace River Alberta region of Alberta, Canada. In the process of developing the plan to re-enter and abandon this well, a methadology for abandonment planning was adopted with three essential attributes: the abandonment should provide effective isolation of all critical zones, operations should allow for evaluation and confirmation of zonal isolation, and the final condition of the well should allow for a simple re-entry to remediate future isolation problems. Throughout the planning and execution of the program, the regulating agency was integrated into the decision-making process. To complete the abandonment, technologies such as casing drilling, downhole cameras, and magnetic ranging were employed along with directional drilling, coiled tubing, and fishing operations. Upon completion, the effectively executed abandonment program met or exceeded prescribed technical and regulatory requirements. The positive results of performing this operation included mitigating environmental impacts, delaying the capital-intensive construction of a future sour gas treatment plant, and allowing the extended operation of the Peace River Complex.
Pushing the Limits for Field Development
Authors: Hoch E. , Ohrt H. B. , Brink D. I. , Flikkema J. , Noman R.
Published: February 2011

The giant Al Shaheen field, offshore Qatar includes a stacked sequence of Lower Crectaceous, carbonate domimated reservoirs of a tight nature and limited thickness. A holistic development approach with real time adaption has been used to push the boundaries for the development and the field is today producing more than 300,000 barrels of oil per day in an injection supported development including the world’s longest horizontal wells of up to 12 kilometres. Innovative completion solutions, providing the means to manage reservoir heterogeneity further supports the adaptive development and have opened new possibilities for enhanced oil recovery.

After discovery in the mid 1970’s the breakthrough in the development came in 1992 when Maersk Oil introduced horizontal well technology from the North Sea tight chalk fields. Effective drainage by the horizontal wells via increased reservoir contact in the thin and tight pay zones has been confirmed from pressure measurements, saturation profiles and seismic data. The horizontal wells have further allowed the 700 sq km offshore development to be developed from 9 platform locations. Development of the tight and thin reservoirs in the Al Shaheen field is challenged by lateral heterogeneities, dipping fluid contacts and varying oil viscosities. The ability to handle heterogeneity is supported through innovative horizontal completion solutions ranging. The development is based on high resoluition 3D reservoir models and development adaption to real time static and dynamic field information.

Obtaining the optimal oil recovery is based on a detailed development strategy tailor made to specific reservoir characteristics and reservoir management and injection and production control.
Hydrophobic Filming Reduces Frac Gel and Mineral Scale Damage
Authors: Weaver Jim , Nguyen Philip
Published: February 2011

Coating proppant with a surface modification agent (SMA) provides cohesion between grains, resulting in the formation of proppant aggregates. This adhesion has been proven throughout many years of use to provide a variety of benefits, including increasing pack porosity and permeability by hindering compaction, reducing proppant flowback, controlling fines invasion into the proppant pack, and minimizing the migration of fines within the pack. A general review of the contributions to improved and sustained fracture conductivity is provided.

There are two additional, important properties of SMA treatments that have not been previously described in detail. The first of these regards the reduction of gel damage expected with the use of guar-based fracturing fluids. Even when highly effective gel breakers are used, significant conductivity damage is often observed with typical guar-based frac fluids. Data are presented showing that coating proppant with a hydrophobic film significantly reduces the conductivity damage caused by guar-based fluids. Treatment with SMA results in wells that clean up faster with increased productivity.

The second property recently demonstrated is that mineral scaling in the proppant pack is inhibited by coating the proppant with a hydrophobic film of SMA. The scaling can be rapid, caused by water incompatibility of the fracturing fluid with the formation. Geochemical scaling can occur when aluminum-based proppants are used because of incompatibilities between proppant and formation mineralogy. Scaling in the proppant pack is often noted by steeper-than-expected productivity decline curves, ultimately leading to premature refrac treatments. It has been found that coating the proppant surface and the formation face with a strong, hydrophobic film significantly reduces the tendency for mineral scaling to occur in the fracture and extends the life expectancy of a fracture treatment.
Application of J-Functions to Prepare a Consistent Tight Gas Reservoir Simulation Model: Bossier Field
Authors: Rojas A.
Published: February 2011

For a tight gas field with a pressure depletion drive mechanism like Bossier Field, it is critical to promptly develop an accurate reservoir simulation model that will help the reservoir engineer understand reservoir behavior, estimate well reserves and evaluate infill and acceleration opportunities.

This paper describes a technique that calculates accurate fluid distributions honoring the physics of the rock such as capillary forces, rock texture, permeability and pore volume distributions. Saturations that make physical sense enable the reservoir simulation model to more accurately estimate reserve and production forecasts that yield a higher level of confidence in the economic evaluations and optimum well planning.

The technique uses laboratory capillary pressure curves coupled with permeability-porosity measurements to generate J-Functions. A J-Function is an average data method proposed by Leverett for correlating capillary pressure data. (Leverett, 1941). The average correlation is based on the fact that geometrically similar rocks have capillary pressure with similar behaviors. The J-Function of geometrically similar rocks will overlay for samples that may differ in permeability by an order of magnitude. The Leverett J-Function is a powerful tool to average data from several samples and to look for outliers of different rock types. Once these J-Functions are identified, they are input into the reservoir simulation model for flow simulation and history matching.

Using this technique the transition from model initialization to flow simulation proved very smooth. The historical production was easily matched increasing the confidence in the outlook. Some of the wells were not in boundary dominated flow; the initial forecasts were underestimated because some of the wells were not in boundary dominated. This technique indicated these reservoir volumes would be produced through existing wells. New infill and acceleration opportunities were developed. Down spacing was determined to be uneconomic.
Natural Gas Lift Method for Wellbores With Multiple Open Formations
Authors: Rodriguez A. , Schott R.
Published: February 2011

Inefficient production of wells with multiple open formations to one wellbore is usually caused by liquid loading, liquid blockage between formations, interference, and crossflow. There are numerous ways that have been tried to flow all the formations efficiently but usually, at the end, the techniques used either give more opportunity to one formation (e.g.: new recompletions) and give up on other formation/s production (e.g.: older, more depleted formations, lowest formation in the wellbore). After long study, testing, and analysis of results we have developed the “Natural Gas Lift” method that can effectively produce all zones with a single string of tubing, keep all selected zones isolated, able to use existing artificial lift equipment like plungers/surfactants through the whole string of tubing to assist in deliquification, and at the same time produce all the formations in the wellbore more efficiently and economically.
Lessons Learned Developing the Eagle Ford Shale
Authors: Mullen J. , Lowry J.C. , Nwabuoku K.C.
Published: February 2011

The Eagle Ford shale play located in south Texas is in its infancy in terms of development compared to other shale plays in the USA. The Barnett shale has been commercially productive since the1980s and the Haynesville has been commercially productive since 2005, whereas the Eagle Ford has only been producing since 2009. Thus, there is significant risk involved in drilling a horizontal Eagle Ford well because the reservoir's characteristics change depending on the location, producing gas, gas condensate, and oil. A few operators have successfully made the transition in the last year from vertical to horizontal-wellbore programs in the gas window and there is a need to shorten the learning curve to successfully develop the play. One such method involves the use of wireline logs, such as cased-hole pulsed-neutron logs (PNL), run in the lateral to determine the reservoir characteristics and to aid in tailoring the hydraulic fracture treatment. Following this horizontal well's completion, a review of the mud log, cased-hole PNL, and tracer and production logs in the lateral in conjunction with the stimulation treatment was conducted to determine which zones produced as expected and, more importantly, which zones did not produce as expected. This paper focuses on reviewing all log data pertaining to this well in combination with the completion treatment and production to identify possible relationships between production performance, the reservoir and the completion, and moreover to determine what would be done differently in future wells, in addition to reviewing additional offset well-data.
Shale Gas Plays: A Performance Perspective
Authors: Sutton R.P. , Cox S.A. , Barree R.D.
Published: February 2011

The production of natural gas from shales traces back to the first well drilled in New York in 1821. Over the past 25 years, access to this resource has grown. Recent advancements in drilling and completion technology has enhanced well production rates and production from shales has increased to where it currently supplies 20% of the gas produced by all gas wells in the United States. Well performance data from these shale plays has been compiled and analyzed to develop insight into these tight reservoirs. These results are compared and contrasted to determine similarities and differences among the plays. Comparisons with classical gas reservoirs and tight gas reservoirs are made to provide additional insight.
Removing Iron Sulfide Scale: A Novel Approach
Authors: Yap Juliet , Fuller Michael J. , Schafer Laura A. , Kelkar Shrihari
Published: February 2011

Iron sulfide is a common scale-formation in sour-gas wells that restricts tubular diameter, reducing well productivity. Compared to other scales, iron sulfide has unique risks associated with chemical removal. For example, due to the corrosiveness of hydrochloric acid (the most common chemical agent for both sulfide and carbonate scale removal), damage to the completion metallurgy at elevated temperature limits its applicability. Another main concern related to the use of acid for iron sulfide removal is the rapid generation of H2S byproduct and the risks associated with production of this toxic gas to the surface.

Owing to H2S toxicity and the resultant elevated corrosion risk, new chemical solutions are needed for high-temperature FeS scale dissolution with low H2S generation. This study describes the development and characterization of a powerful noncorrosive solution for iron sulfide removal based on a chelating agent. Testing shows the fluid dissolution capacity under varied temperatures, scale-surface area, treatment fluid volume, and exposure time. Tests are also included showing the comparative benefits in dissolution capacity compared to other commercially used products such as diethylenetriaminepentaacetic acid (DTPA) and Tetrakis (hydroxymethyl) phosphonium sulfate (THPS). Finally, the mild-pH of the new chemical solution provides significantly lower corrosion rate.

This work describes an altogether new family of chemicals for sulfide scale, providing high dissolution capacity, low corrosion rates, and limited generation of toxic H2S.
Gas Injection Pilot Field Case: An Integrated Monitoring Plan to Tackle Pilot Results and Identify Uncertainties in Heterogeneous Reservoir
Authors: Al-Marzouqi Mariam , Al-Zaabi Najla , Schaeffner Anne , Al-Marasy Hatem
Published: February 2011

The Upper Jurassic formation in Offshore Abu Dhabi is formed of regressive cycles of sedimentation divided into four highly heterogeneous reservoirs (labelled Zones A through D) made up of dolomites/limestones/anhydrytes alternations. In these reservoirs, a fairly dense fault network can also affect fluids movements. Down-dip gas injection is one of the options currently being screened to sustain long term plateau duration of a major offshore Abu Dhabi field. In order to reduce uncertainties related to sweep efficiency in this complex environment, a gas injection pilot, made up of 2 gas injectors and 2 observers, was initiated late 2004.

The Pilot objectives were to: Quantify the impact of tertiary gas injection in lowest Zone D water flooded sub-reservoirs,Evaluate at microscopic scale the remaining oil saturation after gas FRONT,Evaluate the vertical and areal sweep efficiencies,Assess performance of oil producers associated with down-dip gas injection,Evaluate gas injectivity in the pilot area.

A full integrated monitoring and data gathering plan covering all formation reservoirs in the area of the pilot was implemented at project start, including: Extensive data acquisition on newly drilled wells: CMR, FMI, MDT, cores,Tracer injection and analysis,Regular time lapse Cased Hole Neutron and Saturation Logs on observer wells,Interference test between injectors and producers,Regular shut-in bottom-hole pressure data,Frequent production tests including gas sampling for tracer detection and chromatography analysis.

A full integration of all available data led to build a comprehensive and consistent understanding of gas movement and impact over pilot life: Tracer confirmed that gas has been detected in all upper sub-zones (A – D), suggesting vertical communication within the pilot area.Significant vertical differential pressure depletion has been observed between zones.Gas movements are mostly governed by heterogeneities in a multi-layer reservoir that showed the influence of the related fault system and differential pressure depletion.

RST time lapse logs show that microscopic sweep efficiency has been improved by gas injection in water swept zones. This will be confirmed by coring of the observer side track hole planned soon.
Coupled Thermodynamic-Flow Model Simulator for Inorganic Scale Deposition Calculation
Authors: Yee Hon Vai , Foo Khor Siak
Published: February 2011

Every year, millions dollars of money have been spent to remove and inhibit scale deposition in upstream oil industry. Hence it is important to have reliable predictive software to gauge the risk of scaling tendency of a production facility. Several approaches are established to model the scaling tendency during oil recovery. The most conventional models consider the concepts of phenomenological and equilibrium thermodynamic. Both methods are static modeling of an aqueous solution that predicts the scaling tendency at given temperature and pressure. If the scaling assessment is to perform on a producing well where the water composition, three phase (gas-water-oil) distribution and physical conditions (temperature and pressure) are varied at different location, the evaluation process becomes very tedious and impractical.

Therefore, a dynamic scaling modeling instead of static modeling method is required. For the reasons that in addition to serve as a tool to alarm the risk of scale precipitation, it also indicates the amount of scale precipitated and the likelihood deposition location to enable employment of pro-active preventive treatment at early stage. A coupled thermodynamic-flow model simulator is proposed to accurately determine the scaling tendency, quantity and location of inorganic scale deposition in production tubing under flowing condition. This model will couple the effects of thermodynamic equilibrium and kinetic for flow in a producing tubing. This is a major advance on prior state-of-the-art static models that normally predict the scaling tendency for single temperature and pressure input.

A modeling framework is presented in this paper. The proposed scheme in developing the thermodynamic-flow model is described. A number of engineering conceptions were reviewed and all the elements that become the foundation of this thermodynamic-flow model were discussed.

The advantage of having this thermodynamic-flow model is a better flow assurance management, in which scale prevention and treatment design can be refined, leading to unnecessary production lost and reduce treatment cost.
Integrated Reservoir Studies Roll-Up Initiative. A New Industry Step Change Innovation
Authors: Elrafie Emad , Hogg Martin , Mohammadi Hisham
Published: February 2011

An enormous volume of data, models and decisions are gathered and generated in each and every integrated study. The ability and opportunity, however, for a multi-disciplinary project team, including management, to easily browse, review, visualize and analyze in-progress and final cross-discipline study results in a fast, responsive and easily comprehendible manner does not readily exist. Likewise, it is challenging to easily visualize the impact (potential gain and / or loss) of study uncertainties and alternative study decisions.

It is suggested that the integrated Studies Decision Synergy (SDS) initiative is a major new industry step change innovation that is unparalleled in enabling a level of integrated multidisciplinary study synergy across all technical and management professionals at a pace not achieved by traditional industry means. The SDS initiative is composed of five primary components: (1) An integrated multidisciplinary study process (the Event Solution process approach), (2) A proxy, also known as a response surface, to quickly interrogate all study results, (3) Data storage and data mining, (4) Fast, interactive 2D and 3D plotting and mapping, and finally, (5) A user interface enabling process oriented study practice.

This paper presents the evolutionary development (technology and process) and study improvement impact (technical workflows, study decisions and results) of the SDS initiative as an innovation product of the Saudi Aramco Event Solution Study Approach (Elrafie et al., 2007). The paper is supported with sanitized illustrations from completed world-class scaled reservoir studies. Additionally, the paper explores potential SDS applications including: (1) Real-time simulation, and (2) A content rich staff skill set development program.

The ultimate objective of the SDS initiative is to facilitate easy access, retrieval and visualization of all integrated reservoir study data and decisions by a wide multidisciplinary technical and management community with a specific focus on critical study results and the relationships that exist between: (1) Study uncertainties (static, dynamic, timing, and financial), and (2) Study decisions (strategic, well and operations tactics) in the achievement and success of the project objective (i.e., off take rate, oil recovery, oil rate plateau extent, NPV, etc.).
VSP Planning, Acquisition And Processing – Evolution From Zero Offset To Multi Azimuth Walkaway VSP Surveys In The Arabian Gulf
Authors: Khawaja A. M. , Al-Mussawi F. H. , Cao H. S. , Darwish A. A.
Published: February 2011

RasGas Company Limited (RasGas) operates a joint venture in the North Field, the world’s largest non-associated gas field, located approximately 100 km offshore within the State of Qatar. Over the past few years, RasGas has acquired several types of borehole seismic surveys. Initially, a single zero offset Vertical Seismic Profile (VSP) per well head platform was acquired. More recently, this has developed into a comprehensive borehole seismic data acquisition program for each platform. Each data acquisition program had specific objectives which determined how the program was developed. For a comprehensive acquisition program, a detailed geophysical work program was established to meet those objectives and to ensure the safety and cost effectiveness of data acquisition. Following acquisition, the data processing team is encouraged to apply new innovative processing techniques to deal with the data acquisition challenges. An integrated approach in survey planning, data acquisition, and data processing has significant impact and leads to an improved quality product.
Advances in Carbonate Stimulation Methodology – From Wormholes to Long-Term Productivity
Authors: Shuchart Chris E. , Alvarez Jose O. , McDuff Darren R. , Chang Dar-Lon , Troshko Andrey
Published: February 2011

Effective acid stimulation can be critical to achieving the desired long-term production rates from targeted reservoir layers. ExxonMobil has developed an integrated, multi-disciplinary methodology for carbonate matrix stimulation of long completion intervals.1 The methodology is a continuous process which includes geological characterization, reservoir objectives, completion strategy, stimulation design with the necessary experimental testing, implementation, and evaluation. The methodology has recently been customized in collaboration with RasGas to achieve objectives for K1-K32 and K1-K43 completions in the North Field, the world’s largest, non-associated gas field.

Building upon this success, ExxonMobil continues to study the fundamentals of carbonate stimulation and its impact on long-term productivity to enhance the process and apply it to a wider range of reservoirs and well types. This paper presents preliminary results from three areas of ongoing research: (a) improved understanding of 3-D wormhole growth through large-scale experiments and visualization techniques, (b) integrated wormhole modeling and complex fluid flow during stimulation of long horizontal wells, and (c) enhanced post-stimulation evaluation method that integrates stimulation physics, well test analyses, and long-term reservoir performance predictions. Integration of these technological advancements with existing knowledge provides an enhanced methodology for the stimulation of carbonate reservoirs with an increased focus on long-term productivity.
Women in Science and Technology: Engineering a Diverse Future
Authors: Valenzuela M.
Published: February 2011

A continued emphasis on research excellence to address the global challenges of the 21st century will require a highly-skilled workforce. However, recent trends in the scientific and engineering (S&E) communities show a downward trend in human capital. A review of publically available reports, studies, and articles shows women, an under-represented population in S&E roles, offering a viable solution to addressing the human capital gap. Furthermore, increased female representation on technical teams and in executive management positions has shown to correlate to improved innovative, organizational, and financial performance. This paper summarizes literary findings regarding women in S&E industries, their positive influence on technical and economic success, and current challenges and solutions to achieving gender parity.
Minimizing Environmental Impacts (Footprints)
Authors: Mian Mahboob A. , Macwan Nancy
Published: February 2011

With increasing the global warming and climate change issues, in 2009, ADMA-OPCO decided to take concrete steps to minimize the environmental impacts by reducing CO2 gas emissions as company KPIs.

After reviewing and studying the total company emissions and carbon foot print of year 2008, an emission reduction program for year 2009 was launched by targeting to reduce one million standard cubic feet flaring of gas per day.

After taking a number of concrete steps to meet the global challenges, to achieve the 2009 targets and to fulfill the company commitments of flaring and emissions reduction, the company implemented a dedicated strategy and finally succeeded to reduce the flaring and emissions targets by 1.2 million standard cubic feet per day. This in turn reduced the carbon foot print by 0.028 tones per one tone of production which is less than 3% of our production.