bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.