bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Modeling of Polymer-augmented Waterflooding in Heterogeneous Reservoirs
Authors: Teklu Tadesse Weldu , Alameri Waleed , Akinboyewa John , Kazemi Hossein , Graves Ramona M. , AlSumaiti Ali M.
Published: December 2013

Waterflooding is by far the most widely used method to increase oil recovery. All petroleum reservoirs are heterogeneous with varying degree of heterogeneity. Waterflooding could be less effective in heterogonous, channeled reservoirs as injected water moves easily through the channels leaving most oil behind in unswept regions. The reservoir fractures and high permeability channels can create expeditious breakthrough pathways from injectors to producers. Polymer-augmented waterflooding can enhance oil recovery in channel-dominated reservoirs. Polymer helps to reduce high conductivity in the channels, thus diverting injection fluid to the unswept regions of the reservoir. Proper design of polymer flood should be inclusive of the entire drainage volume of the selected well clusters in order to enhance oil recovery while minimizing water cut at the producing wells.

In this study, a finite difference numerical model was formulated and implemented, using implicit pressure-explicit saturation (IMPES) and explicit calculations for polymer concentrations and adsorption effects. The implemented approach was used to study the performance of polymer-augmented waterflooding by varying relevant reservoir parameters. Both homogenous and heterogonous variations of reservoir permeability were considered with more emphasis on channeling. A Langmuir adsorption as a function of polymer concentration was used to account for the irreversible adsorption of polymer during flooding. The effect of polymer adsorption on mobility and permeability was accounted for by a viscosity adjustment and residual resistance factor formulae. With the model’s help, the proper time, to switch back from polymer injection to waterflooding, was determined by analyzing the water cut profile.
Field Specific KPI - An Innovative Approach to Drilling Performance Management
Authors: Weekse Alexander E. , Al-Mumen Adib A. , Hajji Ali A. , Muqeem Muhammad A. , Abouelnaaj Khaled K.
Published: December 2013

The importance of improving the efficiency of drilling operations in the E&P industry cannot be overemphasized, since it directly impacts the overall cost of constructing oil and gas wells. The key performance indicator (KPI) for measuring drilling efficiency is feet per day (ft/d).

In Saudi Aramco, a high level target KPI is normally generated separately for new development oil wells and gas wells, using a benchmark (BM) method based on actual and projected performance. The drilling teams found it difficult to relate individual well performance to the high level KPI target and were unable to properly strategize to improve performance. A new method, the field specific KPI, was developed to complement the BM method and provide a more user-friendly platform to manage performance.

Notable impacts of the new method include; improved planning, accurate monitoring of performance for prompt corrective action; and enhanced accountability and variance analysis from individual wells to fields, departments and the high level. These were demonstrated to be the prime drivers to improve performance.

This paper presents the process of generating the drilling performance efficiency KPIs using the existing BM method and the new field specific method. The scope, strengths, benefits and weaknesses of both methods are also addressed.
Profiling Pressure-Derivative Values - A New, Innovative Way to Estimate the Radii of Investigation in Heterogeneous Reservoir Systems
Authors: Rahman N. M. , Akresh Saud A.
Published: December 2013

The concept of radius of investigation (ROI) has been very useful in assessing the sampled volumes of reservoirs while running well tests. This is also helpful in assessing the (pressure) stabilization times of hydrocarbon units, determining draining areas, and estimating hydrocarbon reserves. Dozens of analytical formulas that are available in the literature have been dedicated to homogeneous reservoirs. However, not much has been reported on the efforts to understand how the ROI concept can be applied to heterogeneous reservoir systems. This study presents a new approach with profiling pressure-derivative values with time in heterogeneous systems to estimate the ROI.

The relationship between the reservoir permeability and the well-test derivative of the pressures measured at the wellbore has already been understood. We will introduce a similar concept to calculate the derivatives at different radial points inside the reservoir for a progressive sequence of elapsed times. By studying the profiles of the derivative values, it is possible to determine how deep the extent of the ROI is. We will also demonstrate that there exists a relationship at a given time between the derivative values at the wellbore and those inside the reservoir.
Characterisation of Hydrocarbon Fluids for Integrated Production Modelling
Authors: Kathrada Muhammad , Fuenmayor Aimara
Published: December 2013

Hydrocarbon fluid characterisation plays a central role in the modelling of oil and gas processes but is still an area that is not well understood. This issue becomes all the more complicated in integrated production system models as the handling of fluid characterisation differs between software packages that model different parts of the oilfield system. Ideally a characterisation methodology that respects the physical behaviour of the fluid while being versatile enough for use by all disciplines is desired. This paper examines some key fluid characterisation issues faced by Integrated Production System Modelling teams and explains how they can be addressed viz.:- modelling the C7+ (heavy) fractionchoice of matching parameters to be used in the regressionthe number of acceptable components that can be used in the compositional model
Record Coiled Tubing Aided Reach and First Real-Time Injection Profiling with Tractor in Extended Reach Well
Authors: Arukhe J. O. , Ghamdi S. , Dhufairi M. , Duthie L. , Omairen K. , Ahmari A. , Harbi M. , Onwuliri C. , Elsherif T. , Othman B.
Published: December 2013

To enhance well performance intervention work is often necessary in field developments. Challenges exist in vertical well interventions and these have been studied and improved over the years. However, horizontal well interventions pose a completely new challenge and a magnified level of difficulty. With extended reach wells certain challenges become almost insurmountable. Basic data acquisition such as production logging where profile data flow is acquired becomes almost impossible to acquire. Yet, this data is vital for decision making. While tractor aided coiled tubing has largely been demonstrated as a preferred deployment technique for cost-effective production logging and acid stimulation combined operations, most of the initial jobs where accomplished via memory production logging in these extended reach wells. This was because the Coiled tubing tractor had no inner wiring. This led to a situation where the subjects of real time evaluation of production flow profile, treatment effectiveness, and injection zone monitoring have remained an industry challenge. A hydraulic tractor aided coiled tubing intervention was introduced as a solution for the development of the extended reach wells in a Saudi field three years ago. This solution aided in the acquisition of the previously difficult data and in addition, aided in deduction of the specific stimulation benefits such as damage skin reduction, improved drawdown, and treatment gains from injectivity increase. Some records which were also set while achieving the well's intervention objectives include 1) attaining the deepest coiled tubing (CT) reach at 29,897 feet (9.11 km) in an extended reach open hole horizontal injector well using a tractor and 2) the first application of real-time water injection profiling enabled through a wired motor head assembly via the tractor. In addition to data, other operational benefits include less equipment to the well site because the same equipment was used for both production logging and stimulation – in particular the coiled tubing reel, amongst others.

The application of real-time informed decisions was critical in overcoming challenges affecting spinner response, operating time and cost, optimizing stimulation design, and yielding a consistent injectivity increase with a true reflection of deep penetration into the damage zone will benefit operators confronting similar intervention challenges.
Quantitative Modeling of Acid Wormholing in Carbonates- What Are the Gaps to Bridge
Authors: Qiu Xiangdong , Zhao Weishu , Chang Frank , Dyer Steve
Published: December 2013

Carbonate matrix acidization extends a well’s effective drainage radius by dissolving rock and forming conductive channels (wormholes) from the wellbore. Wormholing is a dynamic process that involves balance between the acid injection rate and reaction rate. Generally, injection rate is well defined where injection profiles can be controlled, whereas the reaction rate can be difficult to obtain due to its complex dependency on interstitial velocity, fluid composition, rock surface properties etc. Conventional wormhole propagation models largely ignore the impact of reaction products. When implemented in a job design, the significant errors can result in treatment fluid schedule, rate, and volume.

A more accurate method to simulate carbonate matrix acid treatments would accomodate the effect of reaction products on reaction kinetics. It is the purpose of this work to properly account for these effects. This is an important step in achieving quantitative predictability of wormhole penetration during an acidzing treatment.

This paper describes the laboratory procedures taken to obtain the reaction-product impacted kinetics at downhole conditions using a rotating disk apparatus, and how this new set of kinetics data was implemented in a 3D wormholing model to predict wormhole morphology and penetration velocity. The model explains some of the differences in wormhole morphology observed in limestone core flow experiments where injection pressure impacts the mass transfer of hydrogen ions to the rock surface. The model uses a CT scan rendered porosity field to capture the finer details of the rock fabric and then simulates the fluid flow through the rock coupled with reactions. Such a validated model can serve as a base to scale up to near wellbore reservoir and 3D radial flow geometry allowing a more quantitative acid treatment design.
Novel Examples Of The Use Of Surface Jet Pumps (SJPs) To Enhance Production & Processing: Case Studies and Lessons Learned
Authors: Peeran Syed M , Beg Najam , Sarshar Sacha
Published: December 2013

Production from many oil and gas fields is restricted as the reservoir pressure drops. This situation becomes worse when water-cut also increases. The restrictions in production also apply to satellite fields or in deep water applications where long distance transport of fluids is involved. In order to maintain production at an economical rate and also to increase total recovery from the field, a production boosting system is always required. Some production boosting solutions require major investment and major changes or upgrading of the existing production system.

Surface Jet Pumps (SJPs) are simple, low cost, passive devices which use a high pressure (HP) fluid as the motive force to boost the pressure of produced gas and liquid phases. The system enables the flowing wellhead pressure (FWHP) to be reduced in order to increase production, whilst meeting the downstream production pressure requirements. A high pressure fluid is needed as the source of energy or motive flow.

The applications of Surface Jet Pumps include revival of dead or liquid loaded oil and gas wells. The oil and gas industry has in recent years become more aware of their applications and benefits.

This paper covers their main applications including boosting production from selected oil and gas wells, boosting the pressure of low pressure gas, prevention of flaring very low pressure gas, eliminating the need for intermediate compressors, de-bottlenecking compressors, preventing HP wells backing out LP wells and revival of liquid loaded wells. In addition to referring to recent field examples, issues such as performance, ranges of operation, key features of the system and solutions for gas or oil production applications are described. The paper also addresses the economic aspects and pay-back periods. Field applications have shown that the recovery of the capital spent in installing surface jet pumps is generally achieved within a few weeks to a few months.
Challenges in Scale Inhibitor Treatments in Multilateral Complex Wells - A Production Engineering Perspective with Case Study
Authors: Baruah K. N. , Al-Otaibi N. M. , Al-Subaie F. M.
Published: December 2013

Water formed oil field scales impairs fluid flow and can lead to plugging of tubing, valves and surface equipment. When these scales affect well productivity or the integrity of facilities, it is necessary to remove these scales and/or adopt effective scale mitigation strategies. Calcium carbonate (CaCO3) is the most predominant scale in Saudi Aramco crude producers. Conventional bullheading treatments of phosphonate based scale inhibitor into vertical, deviated and horizontal producers are highly effective.

In spite of the success of the scale inhibitor treatment in vertical and conventional horizontal wells, addressing the placement of chemicals in long horizontal and complex producers such as multilateral, maximum reservoir contact (MRC) and extreme reservoir contact (ERC) wells are always challenging and cost intensive. As completions become more complex, the challenges of providing full scale inhibition coverage in multilateral wells also become more complex. Limited accessibility, crossflow, rheology, and high permeability contrasts, all serve to make placement of the inhibitor a critically important component of any squeeze design. This paper describes some of the key uncertainties related to multilateral wells and possible treatment alternatives for proper placement of scale inhibitor into target segment or laterals. This paper also discusses a technical milestone achieved in successful treatment of smart multilateral (SML) wells for the first time in Saudi Aramco scale inhibitor treatment history that paves the way for treatment of such wells in the future. Lessons learned and experience gained to optimize similar future jobs are also described in the paper.
Reservoir Model Updating and Value of Information Using Probabilistic Economic Forecasting
Authors: Singh Harpreet , Srinivasan Sanjay
Published: December 2013

This paper presents a probabilistic economic analysis procedure that accounts for uncertainty in production forecasts arising due to incomplete geologic information. In addition, this paper also presents a procedure to assess the worth of progressive updating of reservoir models using additional data in context of value of information.

For the first objective, a workflow to model reservoir uncertainty and its economic analysis is presented and a procedure for probabilistic economic analysis using real options is developed. The workflow also demonstrates how to incorporate flow rate uncertainty in the real options valuation (ROV) calculations. For the second objective, we compared the value of new information obtained by either drilling an additional exploratory well or acquiring seismic for developing a reservoir model. The base case reservoir model is obtained by conditioning data along 5 production wells and the value of new information is assessed both in terms of uncertainty reduction and increase in economic returns.

Comparison of economic forecast from ROV and discounted cash flow (DCF) approach shows an interesting contrast between the forecast results obtained from these two techniques for all sources of information. The forecast by DCF changes drastically after 2–3 years of production when compared with the forecast by ROV. ROV analysis preserves the uncertainty in reservoir characteristics till the very end of production, while the uncertainty in DCF decreases practically to zero at the end time of production. Even though in this particular case neither drilling an additional exploratory well nor acquiring seismic brought significant improvement to the economic forecast over the base case forecast, the example demonstrates the workflow for updating reservoir models and assessing the value of new information.
Reservoir Simulation to Investigate the Effect of Flow Baffles in a Basin-Floor Fan, Scarborough Field, North West Shelf, Australia
Authors: Sutton J. T. , Glenton P. N. , Fittall M. E. , Moore M. A. , Box D.
Published: December 2013

The offshore Scarborough gas field in Western Australian’s Carnarvon Basin was discovered in 1979 by the Scarborough-1 well. The field contains about 16 trillion cubic feet original gas-in-place (OGIP) of dry gas. It has been appraised by an additional four wells and the 2004-vintage HEX03A 3D seismic survey. Concepts are currently being evaluated for the field’s development.

The field is contained within a large, 800 square-kilometre, very low-relief faulted anticline. The reservoir interval comprises deep water deposits, is divided into a high-quality, high net-to-gross Lower Fan, overlain by lower net-to-gross Middle Fan and Upper Fan. The field is expected to have strong flank and bottom-water drives. The development concepts being considered have minimal tolerance for water production; as such water production is expected to be managed via well shut-ins. Given the low relief of the structure, a significant factor in characterising reservoir performance will be the effect of stratigraphic baffles at various scales, on water movement. Static reservoir models for the Scarborough field were built to incorporate deepwater stratigraphic concepts derived from a plethora of basin-floor fan subsurface and outcrop analogues. These concepts have been applied with systematic distribution of depositional facies, including siltstone baffles bottom-loaded at multiple hierarchical levels.

Dynamic simulation models were built to investigate the sensitivity of sweep efficiency, timing of water arrival and ultimate recovery on a number of key static model parameters. The parameters that were evaluated included: 1) the effect of reduced stratigraphic organisation; 2) the partial removal of baffles at varying stratigraphic levels; 3) the lateral extent and continuity of baffles; and 4) the vertical permeability of siltstones.

The success of the study was facilitated through the effective workings of an integrated, multidisciplinary team of geoscientists and engineers, who maintained frequent communication and feedback through the modeling process.
Understanding Complex Source Rock Petroleum Systems to Achieve Success in Shale Developments
Authors: Dusterhoft Ron , Williams Ken , Kumar Amit , Croy Matt
Published: December 2013

Unconventional oil and gas assets, specifically shale, have captured a tremendous amount of attention in the petroleum industry as new technologies prove that these ultra low permeability reservoirs can achieve economic success in today’s business environment.

Transferring these technologies to new areas where different business environments exist and where, in many cases, the potential plays are not yet well understood requires that understanding of the geology and the reservoir catch up to the engineering solutions for drilling and completing shale wells. This is necessary both for minimizing discovery costs and accelerating economic development in these new environments.

There have been many studies focused on understanding production from shale assets, but these are often centered on a particular region and provide solutions that are very specific and not easily transferred to new regions without significant effort and risk. A detailed understanding of these complex source rock petroleum systems is required to identify specific attributes within a given play that indicate the ability to achieve economic success. This paper emphasizes the need create a very close and collaborative environment that brings together several key disciplines including basin modeling, geology, geophysics, geomechanics, and petrophysics along with reservoir, completions, and drilling engineering. Making intelligent decisions in these developments requires a depth of knowledge that exceeds any one of these disciplines, so this paper looks at several key areas that need to be brought together to accelerate the learning curve and achieve economic success. Tools and processes designed specifically for complex source rock petroleum systems are discussed. These demonstrate the benefits from an improved understanding of the complete system. These will enable improved reservoir modeling, completion design tools, and ultimately enhanced field performance.
Building a Large Scale Sustainable Integrated Asset Model for Greater Burgan
Authors: Joslin J. , Thawer R. , Razzaq E. Al-Abdul , Abdullah F. A.
Published: December 2013

Kuwait Oil Company (KOC) is using several models to assist with the planning of the future of the Greater Burgan field. Integrated asset modelling (IAM) is being used to understand the dynamics of the full production system and find opportunities for optimisation. Abnormal declines have been observed in some of the surface facilities. Further investigation revealed scale deposits in some flowlines causing a restriction. IAM was then used to identify similar restrictions and quantify the overall benefit of their removal.

Combining wells, flowlines and facilities of a field into a single integrated asset model in any organisation is always challenging. It requires a vast amount of inputs and a good understanding of the dynamics of the field. With an operating asset, such as the Greater Burgan field in South East Kuwait, it is likely that the inputs would have changed shortly after starting. Existing wells occasionally switch from high to low pressure systems and new wells are being connected on a regular basis.

Bringing together 1000+ completions with an associated flowline network requires a disciplined approach. There should be careful attention to the benefits of modelling particular features and to what level of detail. For example, the internal diameter changes due to the completion accessories will take a long time to enter and offer little benefit to the overall result. Decisions need to be made to allow early and timely results. Sometimes a rough and quick model can help to proiritise the high impact items affecting the entire field.

KOC has taken two approaches to create such a large scale model. One simple, one detailed. The purpose of both models is to understand where to focus investment by understanding the benefits of changes in the system like debottlenecking, routing options and expansions.

By building a simplified multiphase flow simulation model with the latest field data KOC has identified a potential gain of 30,000 BOPD to the current field oil rate. This would come from the removal of restrictions of varying magnitudes in 93% of the flowlines. However, further analysis shows that about 90% of the gain comes from just 200 of the completions and flowlines. With further study using this model it is estimated that twice as much gain will come through careful optimisation.

The advantage of the simplified model is that its building is easy to automate. It can be updated frequently using the latest field data in the company database. This means that the model can stay live as rebuilding can be done in less than 3 hours. The time required to build the process and initial model took 3 weeks. The detailed model is estimated to take 12 months and is nearing completion. Some of the same processes used in the simplified model have already helped to reduce its overall building time.
Forecasting of H2S Production due to Aquathermolysis Reactions
Authors: Barroux C. , Lamoureux-Var V. , Flauraud E.
Published: December 2013

Steam injection has been recognized as an efficient process for recovering hydrocarbons from heavy oil and bitumen reservoirs. However, it is now well known that the steam injection induces chemical reactions within the reservoir, called aquathermolysis and yielding acid gases. Hydrogen sulfide (H2S) being highly toxic and highly corrosive, even at low concentrations, it is of major importance to forecast H2S production. However, until now, there are only very few publications relating reservoir simulations of steam injection processes accounting for thermal and compositional effects in a chemically reactive context.

The proposed paper relates a work focused on H2S production forecast during a SAGD process from aquathermolysis experimental results and simulation. After a description of the aquathermolysis experiments, the simplified sulfur-based kinetic model deduced from the experimental results is presented. This sulfur-based kinetic model has been used to build a thermo-kinetic component-based model usable in a compositional and thermal reservoir simulation. A simulation of the experimental aquathermolysis reactor being run for validating the thermo-kinetic model, the simulation results of H2S production and oil SARA composition versus time are shown to be in good agreement with the experimental results.

Then, the thermo-kinetic modeling has been input in a cross-section model designed for simulating a SAGD process. The H2S production results were found to be consistent with published field data.

The work related in the paper contributes to provide a new insight to the simulation of H2S production by aquathermolysis, through the presentation of a simplified modeling of the aquathermolysis reactions, and the description of a methodology for building an EOS (Equation Of State) model compatible with the reactive model.

The followed approach is shown to be usable for forecasting H2S production due to an aquathermolysis phenomenon during a steam injection process.
Advanced Signal Analysis of an Electrical Submersible Pump Failure Due to Scaling
Authors: Mehidi M. N. , Bukhamseen A. Y.
Published: December 2013

The present paper is concerned with a study of electrical submersible pump failure due to scale build-up. From motor current signals recorded several weeks before the failure, weak fluctuations were recorded, indicating a change in the motor load. The advanced signal analysis of the motor current data revealed the presence of a dynamical character of the electrical submersible pump signal when scale started rapidly building up in the pump stages. Based on the raw data from the motor current draw a dynamical cascade was identified from the current marked with the superimposition of several characteristic frequencies added in time and developing a chaotic trend. The analysis is conducted with different signal analysis recognition tools such as Fourier transform, wavelet transform and chaotic attractors, which describe the nature of the scale signature in the current logs clearly. This analysis can be the first step towards developing real time diagnostic tools to predict ESP failures and acting accordingly.
Well Test Rate Conversion to Compositional Wellstream
Authors: Hoda Mohammad Faizul , Whitson Curtis Hays
Published: December 2013

Well test rates are measured with test separators operating at varying pressure and temperature during initial production tests for a new well and during periodic tests used to monitor well performance and allocate multi-well production separator rates.

Converting test separator gas and oil volumetric rates to a common (fixed) set of surface separator conditions is useful to ensure consistent history matching and rate allocation, development of valid inflow performance relations, and correlating well performance changes over time. This paper provides a method to convert reported test rates to a molar compositional wellstream rate. This compositional wellstream will exactly reproduce the reported test rates at the separator conditions prevailing when rates were measured. The compositional wellstream rate can then be re-processed through a fixed set of separator conditions to provide total surface gas and stock-tank oil rates.

The requirements for converting test rates to a compositional wellstream include: (1) an appropriate EOS model, (2) an estimate of the wellstream composition – the "seed feed", (3) test separator volumetric rates, and (4) test separator conditions of pressure and temperature. The seed feed is usually the previously-determined wellstream composition from an earlier test. The seed feed is flashed at test separator pressure and temperature, resulting in equilibrium gas and equilibrium oil compositions. These equilibrium compositions are recombined in a ratio that yields exactly the test separator gas-oil ratio with the EOS model, thereby yielding wellstream composition. Properties of the separator phases are used to convert separator volumes to moles and thereby wellstream molar rate.

Sometimes a similar conversion is needed for volumetric gas and oil rates resulting from a multi-stage separation process. An important example is conversion of black-oil rates to compositional wellstreams, where the black-oil PVT tables have been generated from a multi-stage separation process.

Finally, we discuss the processing of compositional wellstreams through a higher-level (group, field, or asset) process facility that takes into account the total feed composition of the process facility, and how to back-allocate well contributions of total product rates.
Efficient Upgrading Philosophy to manage Future Effluent Water in the Kuwait Oil Company, Greater Burgan Field
Authors: Ali Farida Mohammed , Al Wazzan Roqaya , Robinson Mike , Thawer Roxy
Published: December 2013

Over the forseeable future in support of the KOC 2030 strategic objectives the Greater Burgan Field will maintain its current plateau production whilst the water cut is predicted to increase from 23% to more than 60%. The requirement in any giant field is the implementation of timely upgrades to manage the required incremental gross handling capacity, reduce infrastructure complexity that will result from increasing well count and to manage investment and activity in line with the development needs.

To meet these objectives it is required to reduce the normal capital project cycle of 8 years and wherever possible, procure standard equipment to reduce complexities in the new facility upgrades which will also provide flexibilities in installation and maintenance. To meet these challenges we required a common equipment philosophy and a faster procurement strategy.

A concept was developed to modularize the upgrades into common, standard sized, skid-mounted (where possible) units to meet the increasing production system throughput and infrastructure de-congestion and combine these with long term supply contracts to manage the logistics and efficiency of rapid turn around in upgrades. This concept is already being implemented in the design and installation of remote headers and will create a step change improvement in our upgrading process when applied to the rest of the facilities upgrades.
Successful Application of Metal-Crosslinked Fracturing Fluid with Low-Polymer Loading for High Temperature Proppant Fracturing Treatments in Saudi Arabian Gas Fields — Laboratory and Field Study
Authors: Malik Ataur R. , Bolarinwa Simeon , Leal Jairo A. , Duarte Jorge , Vielma Jose R. , Soriano Eduardo
Published: December 2013

For the past decade, Saudi Aramco has been successfully exploiting tight gas sandstone formations. These formations are routinely hydraulically fractured to enhance gas production, but as the development of the existing fields continues into deeper formations the exploration of new reservoirs emerges. New challenges are now being faced especially, considering that higher temperature is being encountered and the fracture fluids currently being used (based on borate crosslinker) are not stable enough to tackle the extreme conditions.

Metal-crosslinked fracture fluids have long been the most popular class of high viscosity fracturing fluids. Primary fluids that are widely used are titanate and zirconate complexes of guar, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), or carboxymethyl hydroxyethyl cellulose (CMHEC). Zirconium-delayed CMHPG are typically used for high temperature applications. These types of fluids provide high temperature stability with low polymer loading with the added benefit of salt compatibility. The proppant transport capabilities of the metal-crosslinked fluids are excellent. Zirconium-delayed CMHPG fracture fluid is currently the preferred fluids due to its extraordinary stable characteristics for bottom-hole temperatures (BHTs) up to 375°F.

This paper addresses the research, lab testing and successful application of a metal-crosslinked fluid used for fracturing operations of a high temperature (312 ~330 °F) tight gas reservoir in Saudi Arabia, with its post-treatment evaluation to optimally develop these reservoirs in harsh bottom-hole conditions.
Rapid Application of New Solution Maintained Wellbore Integrity in Fractured Carbonate Formation
Authors: Szabo Joseph J. , Clapper Dennis K. , Lewis Tom G.
Published: December 2013

Wellbore integrity continues to be a primary concern in drilling operations due to AFE over-runs resulting from delays, and in extreme cases, re-drills when integrity is lost. In the case of tensile failure, it is vital to have a solution that is versatile, easily prepared and quickly placed to remediate a loss-of-integrity event. A one-sack, quick mix and pump fiber pill formulation has been developed that addresses these common operational concerns. Previous field trials have shown this one-sack, rapid mix and pump material to work quickly and effectively in shale- and sand-based formations.

Recently, this material has also been shown to work successfully in fractured chalk formations. Fractured-chalk formations show many similar physical characteristics to fractured carbonates, but many differences from shale and sand-based formations. This is a great leap forward in showing the versatility and applicability of this lost circulation solution because fractured carbonates are present in many of the world’s drilling areas. Through these new trials it is now evident the material is effective across most of the physical conditions encountered worldwide. These trials also contain a new and successful utilization of calcium carbonate as a weighting agent in the formulation of the one-sack rapid mix (OSRM) pill, opening a new area of utilization for this material at lower densities. The successful use of calcium carbonate, rather than barite, also enables the OSRM pill to be further customized through the use of different, and assorted, particle sizes available in calcium carbonate grinds. In addition, it is also important to note that this one-sack, lost-circulation product has been given a green environmental rating in Norway, demonstrating high environmental compliance for most markets worldwide.
Design and Analysis of Interference Tests – Application to a Seven-Spot Inverted-Pattern Waterflood Pilot in the Wara Formation of the Greater Burgan Field, Kuwait
Authors: Gazi Naz H. , Abdulla F. A. , Al-Naqi M. , Al-Kandari I. , Dashti L. , Al-Qattan A. , Al-Farhan F. A. , Maizeret P.-D.
Published: December 2013

Interference testing is the oldest but still the most effective way of establishing communication between wells and determining the reservoir transmissibility. However, data can be difficult to interpret and the results can be misleading. Fortunately, simple steps can be performed to validate the data and obtain first estimates of the formation parameters. We demonstrate this methodology for an interference test performed in the Greater Burgan field in Kuwait.

A pilot project was started to understand how to successfully inject water in the Wara reservoir. Seven wells were drilled in an area away from the existing wells: one injector at the center of a 250 m-radius hexagon formed by six producers. An interference test was performed between the injector and the producers. The main objective of the study was to evaluate the transmissibility between wells and the permeability anisotropy in the formation. In five of the producers, the target sands were oil bearing, whereas surprisingly, the same sands were water bearing in the sixth well. Consequently, a second objective was added to the study: to check whether the sixth well was in communication with the other wells and to determine the origin of the water.

The tests showed that all wells responded to the pressure pulse, including the sixth well, thus refuting the assumption that a fault was isolating it. The fall-off analysis of all the wells highlighted the presence of boundaries, a finding that was consistent with the fluvial depositional environment. Moreover, the analysis showed that the channel was narrowing near the sixth well. Therefore, we could hypothesize that the sixth well had been drilled in a zone with perched water trapped by the channel boundaries. A few weeks after the test, the oil cut started to increase in that well, confirming our hypothesis.

The findings from this pilot project proved the efficiency of waterflooding as secondary recovery method and were used to design the pressure maintenance program.
Foamer Application for Sajaa Asset gas Wells
Authors: Poulose Biji , Hamadi Masoud Al
Published: December 2013

Sajaa gas field is one of the oldest gas fields in the Northern Emirates and Petrofac currently holds accountability for the Sajaa asset wells. This mature asset suffered from declining reservoir pressure and increased problems with liquid loading where entrained liquid dropped out in the vertical well bore, thereby restricting the flow of gas and fluids to the topside processing facility. A detailed study was conducted to understand the different techniques available for overcoming this liquid loading problem which impeded gas production rates.

After studying several methods to overcome this liquid loading issue, foamer injection was suggested for the wells which had intermittent flow patterns. The foamer application was also chosen as one of the cheapest and easiest means for overcoming liquid loading issues. Foamer treatment for Sajaa fields was initiated two years ago and a substantial increase in gas production was recorded for most of the wells with this foamer application. The foamer product selection was carried out based on modeling and subsequent lab tests. Close monitoring of well behavior to the foamer application was conducted and detailed case histories were developed for some of the wells.

A tremendous improvement in gas production rate was noted for one of the wells in Sajaa field – ‘Sajaa S-36’ (9⅝" completion). Unlike most of the other Sajaa wells, S-36 was fitted with capillary injection tubing where the foamer chemical was injected downhole through the ¼" tubing. The well performance was monitored for a period of one year and sufficient data was collected highlighting the foamer performance.

This paper presents the results of the foamer downhole injection campaign and gives an overview of the treatment methodology. An insight into the factors influencing the foamer performance, selection methods and the optimization techniques employed during the foamer injection trial are also presented.
Carbonate Stimulation with Biodegradable Chelating Agent Having Broad Unique Spectrum (pH, Temperature, Concentration) Activity
Authors: Reyes Enrique Antonio , Smith Alyssa , Beuterbaugh Aaron
Published: December 2013

The use of chelating agents to stimulate carbonate reservoirs has continued to increase since their first inception. A distinct chelant is presented in this paper. The new chelant is fully biodegradable and can be used in fluid formulations that specifically target the formation characteristics.

The chelating agent can be used in concentrations from 0.2 to 0.6 M, with a pH of 1, 2, or 4, and is effective from 125 to 350°F. The specific fluid composition is a function of the mineralogy and rock lithology as well as temperature. Core flow testing at less than 200°F shows optimum dissolution with low-concentration, low-pH fluid; while, at temperatures >200°F, higher concentrations of chelant is optimum. The representative pore volume (PV) breakthrough curves provide an indication of the distinct reactivity of this chelant to other known chelants. Analytical characterization of the spent fluid (elemental analysis, pH) and of the core (CT imaging) are used to show that the activity in which the fluid displays on select limestone (calcite or dolomite) cores can be exploited to enhance wormhole structure generation. Core permeabilities ranged from 0.4 to 10 md, and core dimensions (radius × length) corresponded to 1- × 4-in., 1.5- × 6-in, and 2- × 6- or 10-in., respectively. The chelating fluid maintains in solution dissolved calcium, a property that is magnified because of the ease with which the acidic fluid spends as it is transported through the limestone matrix.

The concentration of the chelant can be optimized to a specific pH to maximize its dissolution capacity. Overall, the new chelating agent affords superior complexation capacity from low pH to near neutral pH values while dissolving the minimum amount of mineral and effectively increasing porosity. The chelant expands the range of available options in the area of treating fluids for carbonate stimulation.
High Resolution ChemoSteering in Drilling Horizontal Wells, Kuwait
Authors: El Gezeery Taher , Al Anezi Khalaf , Ismael Abdul Aziz , Silambuchlvan Jeevan , Latif Ahmed A. , Prakash Das OM , Padhy G. S , Estarabadi J. , Marai N. , Shoeibi A. , Khan F.
Published: December 2013

Advanced multilateral well drilling & completion requires the application of innovative technologies while drilling to place the well in sweet spots by managing all the geological uncertainties. The smart level-4 multilateral well with dual stacked lateral was drilled by integrating advanced Real-Time geo-steering formation characterization along with geochemical, advanced gas analysis and seismic data interpretation.The Burgan reservoir consists of vertically stacked channelsands associated with geological heterogeneities along with series of fault networks connected to the aquifer at the bottom. The reservoir contains ultra-high water mobility with down hole oil viscosity of about 40cp enhances water breakthrough and requires customized ICD and ICV completions to enhance dry oil production and maximize oil recovery. Real-time geo-steering performed on Multi-lateral well by utilizing advanced technologies including High resolution Geochemical Analysis has been utilized in Real-Time to identify "geochemical proxies" and allow geochemical steering, distance to boundary tool using 4 resistivity curves with deep spacing Geosignal, At-bit measurements and density image to correct well positioning and locating faulted areas.

The pre job planning had two components such as: (i) building a geosteering model based on offset well logs, geological and geophysical information and (ii) preparation of geochemical model based on XRF analysis of core chips from offset wells. The later model was calibrated through logs and utilized further to predict key rock attributes such as: (a) detailed lithological variations generally beyond the resolution of LWD logs, (b) detailed mineralogy to determine the diagenetic overprint and (c) depositional environment of different Burgan sand facies. Continuous interpretation and integration of XRF and petrophysical analysis supported by LWD data was a key factor for real-time geosteering operation.

Such integrated approach also resulted in successful placing the wells with maximum reservoir contact and also was very instrumental for (i) isolation of potential trouble zones, (ii) segmentation of horizontal sections and (iii) optimization of nozzle sizes of the ICDs and hence planning of smart completion designs.
Application of Bacterial Mat for Optimized Gas Hydrate Recovery
Authors: Dubey A. , Saxena A.
Published: December 2013

With increasing energy demand, the oil and gas industry requires new technological developments in the field of unconventional resources along with sustainable development. In this paper we put forward the concept of Bacterial Mat for optimised recovery from marine gas hydrates. Gas hydrate is a solid compound in which methane is trapped within a crystal lattice of water under high pressure and low temperature condition.

The primary condition for the stability of gas hydrate is high pressure and low temperature i.e. a minimum depth of 300m and a temperature lesser than 2°C. Several technologies have been experimented for the extraction but the main problem faced was uncontrolled liberation of methane which is a powerful green house gas.

Our suggestion is to use Bacterial Mat for the optimised recovery of gas hydrates. This bacterial mat contains Archae bacteria. These bacteria can survive in extreme environment and can produce methane from CO2 & H2O. This process is exothermic and can raise the temperature to 140°C leading to escape of methane from gas hydrates. These bacteria will breed on an artificial animal intestine mat from which they will get nutrients for growth. The bacterial mat will be sent to the seabed and fixed to the bed with its arms on the edges where gas hydrates are deposited. After achieving the desired saturation of gas, it is produced from the sea surface installation.

The above suggested methodology is an optimised and economical way to recover gas hydrates. Firstly it will help to change the focus of extracting resources from conventional to unconventional resources. Secondly, it will lead to sustainable development and reduce the hazard of global warming to a large extent. Thirdly, this technology has huge potential in the petroleum industry.
Integrated Water Management and Surveillance Strategies in a Giant Carbonate Field from Saudi Arabia
Authors: Alghazal Mohammed A. , Razally Ali M. , Alhuthali Ahmed H.
Published: December 2013

Excessive water production and unbalanced sweep in a water flooded reservoir can significantly impact oil production and increase water handling expenses, jeopardizing the overall economic recovery of hydrocarbon within the field. The objective of this paper is to provide a review of various integrated water management techniques successfully implemented in a carbonate field in Saudi Arabia, balanced under the critical monitoring eye of a systematic strategic surveillance program deployed to assess sweep efficiency across the field.

Complex networks of super permeable streaks and sub vertical fractures highly influencing fluid transport media within the subsurface characterize this carbonate reservoir. Understanding fluid flow mechanism in this heterogeneous gravity dominated reservoir is a predominant factor influencing the various approaches designed to manage water production in the field. The key management strategies that have been introduced are horizontal sidetracking of existing vertical wells at the top of reservoir, rigless water shut-off jobs and employing cyclic production mode for wells with very high water cut. In addition, Inflow Control Device (ICD) completion technology is being deployed within lateral sections that have encountered flow dominating geological features, such as fractures or super-K, providing a practical, innovative solution for an effective homogenized flow distribution along the lateral intervals. Collectively, these employed practices have been found successful in substantially reducing water production and improving oil recovery as supported by field data.

Concurrent with these water management strategies, sweep conformance and flood front movement are regularly monitored by conducting a rigorous Strategic Surveillance Master (SSM) plan across the whole field. The results from saturation and production profile logs confirm efficient vertical and areal sweep conformance and ensure the effectiveness of the integrated water management strategies employed in the field.