bluuebunny/crossref_metadata_2025 huggingface dataset:
WAG Performance in a Low Porosity and Low Permeability Reservoir, Sirri-A Field, Iran
Authors: Taheri A. , Sajjadian V. A.
Published: December 2007

Sirri-A is a large offshore producing field which is located in the Persian Gulf, in Iranian sector, with an OOIP of about 2 MMMSTB. Its reservoir with porosity range of 3-21 percent and a permeability range of 0.1-3 md is situated in Ilam formation which is a complex limestone formation. Because of these range of porosity and permeability, specific strategy that was used includes the use of horizontal injectors and producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. The main production mechanism during natural depletion scenario is rock and fluid expansion. Recently, during this production scenario, the field initial production rate of around 20000 BOPD declined rapidly to around 9000 BOPD within four years. The sharp decline was common in all wells. Therefore, it can not be considered to be local well and/or formation damage. So this reservoir is a candidate for an EOR process. Simulation results show that the most economical method to produce this reservoir is WAG. This production strategy has resulted in better efficiency and therefore higher oil recovery and good economics.

The simulation results illustrate the influence of WAG injection parameters like WAG ratio, WAG half-cycle period and injection rates on recovery process. Also the effect of some uncertain parameters like three phase relative permeability model and anisotropy on WAG performance in this low porosity and low permeability reservoir is investigated.
Fracture Design Considerations for the Development of Tight Gas Formations
Authors: Ionescu G. F. , Awemo K. N. , Pusch G.
Published: December 2007

Tight gas reservoirs bear large resources of gas all over the world. Due to their very low matrix permeability (< 1mD), the production from these formations is usually below an economical limit, if the reservoir does not contain natural fractures. The use of horizontal wells alone can not significantly improve the economics of tight gas projects. A promising combination is the use of horizontal wells and vertical fractures in order to enlarge the drainage area and improve the reservoir sweep efficiency. For the successful application of this technology the design of the well patterns and fracture design shows an important impact on the production rate and recovery factor.

This paper describes the field development options based on a numerical simulation of the production forecast and recovery of multiple hydraulically fractured horizontal wells. Practical formation damage problems, as for example mechanical and hydraulic skin effects are taken into account.

The design procedure is a multi-variant analysis of the key parameters, as fracture length, conductivity, fracture spacing and number, length of the horizontal well and well spacing. Water based fracture fluids do not represent an ideal operating solution if the rock contains large quantities of fine dispersed clay cements (illite). Fracture damage may drastically reduce the flow capacity in the fracture. The practical considerations include the different options to stimulate the reservoir with packed and un-packed fractures, to avoid formation damage from fracture fluids and improve reservoir sweep efficiency.

The paper underlines the needs to improve hydraulic fracture performance in water sensitive reservoir rocks, as for example the illite cement type of Rotliegendes sandstone.
Revival of Openhole DST: Compromising Between Wireline-Formation Testing and Cased-Hole DST
Authors: Ostrowski L. P.
Published: December 2007

Exploration well testing has gone through several changes over the past twenty years. While open hole Drill Stem Testing (DST) based on conventional technology with mechanically set packer was gradually replaced by inflatable packer based DST tools, cased hole DST became a standard for many exploration companies, particularly offshore. Today, some companies still avoid open hole testing based result of poor success ratios of outdated conventional tools. Also, wireline formation testing has become more frequent due to advances made in wireline test tools.

However, because of greater ability to obtain reservoir productivity and skin measurements, DST continues to be widely used, though cost and environmental issues limit its application in certain areas. Land rigs are natural candidates for open hole DST due to the content and quality of information obtained, as well as well as lower cost of the open hole DST service compared to wireline formation testing. Open hole DSTs are quick and simple to run. Hydrocarbons do not need to be produced to the surface, but a significant volume of reservoir fluid can be produced. Due to these advantages we see an increasing trend to deploy inflatable open hole DST tools on on-shore exploration rigs. The benefits are so convincing that operators using small jack-up rigs consider performing this type of tests as well.

This paper summarizes all aspects of open hole DST with respect to information gained, time needed and related cost. The differences between old type of conventional DST and inflatable DST are highlighted and success ratios provided. Safety aspects are discussed by comparing with wireline formation tester and cased hole DST operations as well as the basic economics.
History Matching of a Tight Gas Reservoir Stochastic Model Using Semiautomated Methods
Authors: Schaaf T. , Martin A. , Coureaud B. , Clay C.
Published: December 2007

This paper presents an integrated methodology (using versatile history matching software) for constraining 3D stochastic reservoir models to well data and production history and its application to a real case (a tight-gas reservoir in the Southern North Sea).

The approach is to formulate the history matching problem as a minimization problem where the objective function to be minimized is the squared difference of the real production data values and the corresponding simulated data. To resolve this inverse problem, we use gradient based optimization techniques to update the entire simulation workflow, thanks to advanced parametrization techniques. The set of model parameters characterizes the stochastic geological model (including the diagenetic modeling) and the fluid flow simulator, which allows the facies distributions (and their associated petrophysical properties), diagenetic overprint and well properties (such as skin) to be modified until an acceptable match is obtained.

The parametrization technique is coupled to constrained optimization algorithms to ensure that model parameters remain within realistic bounds of the geological settings and ensures that the geologically derived stochastic properties of the initial reservoir are preserved throughout the history matching process.

This application shows how the combination of a versatile history matching tool with efficient parametrization techniques can improve the quality and efficiency of a geologically driven history matching process. The speed of this process will be valuable when analyzing a set of history matched models allowing a better assessment to be made of the risk and uncertainty associated with predictions of future performance.
Development of the Strasshof Tief Sour-Gas Field Including Acid-Gas Injection Into Adjacent Producing Sour-Gas Reservoirs
Authors: Behrend J. , Chugh S. , McKishnie R. A.
Published: December 2007

OMV operates two producing sour gas reservoirs in Lower Austria: the Reyersdorfer Dolomite (shallow reservoir) and the Schoenkirchen Uebertief Dolomite (deep reservoir). A new, separate reservoir called the Perchtoldsdorfer Dolomite (Strasshof Tief Field) has been discovered, and options for how its acid gas can be handled are being investigated. The two currently producing reservoirs deliver to a gas plant with a 30 t/d sulphur plant. The sulphur plant is too small to accommodate the additional production. OMV has evaluated acid gas injection as an alternative to a new, larger sulphur plant. Acid gas injection could be into either the Reyersdorfer Dolomite or the Schoenkirchen Uebertief Dolomite. In either case, injection would be occurring concurrently with production. Three injection scenarios are contemplated: 200, 400 and 800 103 Sm3/d (6.4, 12.8 and 25.6 MMcf/d). The applied acid gas composition is CO2 (80 %), H2S (16 %), N2 (3 %) and CH4 or C1 (1 %).

The intent of this project was to determine if sufficient injectivity and storativity is available in either the Reyersdorfer Dolomite or the Schoenkirchen Uebertief Dolomite. Compositional modelling and the prognosis of the breakthrough time at the producing wells was carried out to determine the contamination risk to existing production.

The simulation work included 1)Generating compositional numerical simulation forecasts of production rate/composition forecasts under concurrent injection/production scenario 2)Modeling in-situ miscibility and gravity separation effects of acid gas 3)Evaluating risk scenarios for existing production and determine optimal solution.
Case History of the Matzen Field/Matzen Sand (16th TH): A Story of Success—Where is the End?
Authors: Kienberger G. , Fuchs R.
Published: December 2007

The Matzen Sand (16th TH) was discovered in 1949. To date, some 42.3 million m3 (266 million STB) oil and 3.75 billion m3(Vn) (140 billion scft) gas were produced which leads to a recovery factor of 48.5 %. Average water cut is 93.5 %. Mean porosity is 27 %. The oil has 25°API gravity. The sand is relatively homogeneous and exhibits a pay thickness between 1 m up to 70 m (3.3 ft to 230 ft). ‘Hard layers’ (tight streaks) reduce vertical permeability in certain areas.

1968 a peripheral water injection project was commenced. Discontinuous hard layers distributed throughout the reservoir affect water flooding. Sweep efficiency is related to these hard layers. Areas of unswept oil between these tight layers have been proved by reperforation of certain producing wells.

In 1996 natural gas injection started into the gas cap which caused a reduction of the oil production decline by 50 %.

Successful production history of the 16th TH results from proper reservoir management through 55 years of field life.
Application of Real Time Surveillance and Optimisation Tools on a Large Asset
Authors: van Zandvoord Walrick E. J. J. , Maskery Ali Abdullah , Schmid Tom
Published: December 2007

This paper demonstrates the use of real time well surveillance and optimization tools in the Northern Fields of Petroleum Development Oman LLC (abbreviated as PDO in the rest of this paper). The use of such software as part of the Real-Time Infrastructure (including a data historian and PDO's in-house developed Production Portal for long term real time data trends) has been one of the key enablers to create renewed focus in Well & Reservoir Management. Furthermore it was one of the contributing factors in significantly reducing unscheduled well deferment.

The software that was used is highly modular, hence was used to target specific PDO problems quickly and cost-effectively. Monitoring, reporting and alarming functionality was used to identify problems, while the analysis functionality was used to find causes of those problems. In some fields real time flow estimation was implemented based on data driven well models (i.e. empirical as opposed to physical well models), which give a continuous real time estimate of oil, gas and water.

Intensive use of the data has led to reduced deferment, early identification of well problems and lower decline rates by e.g. identifying fracturing and short-cutting of injectors to producers. PDO's Real-Time Infrastructure has built in data integration capabilities, which allow easy integration of the data throughout the company without requiring duplication of the data.

The combination of effective use of all the applications in and around the Real-time Infrastructure and complementary initiatives (mostly with a focus on wells) have improved production and mitigated decline, equivalent to a sustainable production improvement of around 7,000 bpd.
Real-Time Transmission of High-Resolution Images
Authors: Fulda C. , Akimov O. , Baule A. , Bethge J. , Roessel T. , Tilsley-Baker R.
Published: December 2007

Recent advances in high-resolution imaging are well perceived by the oilfield industry as an aid to refine reservoir characterization. The availability of high resolution image data in real-time allows for improved decision making and more optimal wellbore placement when navigating through the reservoir. However, the transmission of high resolution image data to surface is limited by the bandwidth offered by mud pulse telemetry systems.

This paper describes a new concept for transmitting imaging data to surface in real-time. The concept includes a highly flexible and effective compression scheme that can be used for all currently available and future telemetry systems. Image transmission parameters can be modified via downlink commands at any time without interruption of the drilling process. In this way, image parameters can be optimally adjusted to suit the available telemetry rates and proportion of the bandwith dedicated to image transmission. This flexibility allows customization of the real-time imaging service to optimize the geosteering process and the ability to provide high resolution data over specific zones of interest.

The relationship of pixel size, telemetry rate and the real-time image parameters of latency and redundancy are discussed with reference to real-time resistivity images from field measurements transmitted at different telemetry rates and the corresponding memory images.
Field Case Studies: Damage Preventions Through Leakoff Control of Fracturing Fluids in Marginal/Low-Pressure Gas Reserviors
Authors: Paktinat J. , Pinkhouse J. A. , Williams C. , Clark G. A. , Penny G. S.
Published: December 2007

The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension, contact angle and leakoff control. However, many of these chemicals adsorb rapidly within the first few inches of the sandstone formations, reducing their effectiveness in deeper penetration. This phenomenon causes surfactants to adsorb or plate-out reducing their effectiveness in post fracturing fluid recovery.

This study describes experimental and field case studies of various surfactants used in the oilfield. Several different surfactants including a nonionic ethoxylated linear alcohol, nonyl phenol ethoxylate, an amphoteric, a cationic and a microemulsion system were investigated to determine their adsorption properties when injected into a laboratory sand packed column. A laboratory simulated comparison study of commonly used surfactants and microemulsion was used to identify their leakoff and water recovery properties from gas wells.

Field data collected from Bradford, Balltown and Speechley sandstone formations confirmed experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths, damage surrounding the fractures and drainage areas with various fluid systems. These investigations and presented case studies can be used to minimize formation damage.
Near-Surface External Casing Corrosion in Alaska: Cause and Mitigation
Authors: Dethlefs J. C. , Blount C. G. , Bollinger J. C.
Published: December 2007

Recently, a number of external casing failures on a group of relatively new wells in the Kuparuk field of Alaska prompted an investigation into the cause. The investigation determined that external surface casing corrosion failures had occurred near the top of the casing cement within the conductor.

The surface casing corrosion was found to be caused by repetitive events of surface water entering into the top of the annulus between the surface casing and the conductor above the primary cement top. Testing of water and cement samples taken from the field indicate that the addition of oxygenated water and chemical salts that leach from the cement creates a low-resistance electrolyte resulting in an extremely corrosive environment. The yearly replenishment of oxygenated water in this environment sets up an electro-chemical cell that corrodes the surface casing. Elevated casing temperatures (~125 deg. F) accelerate the corrosion rates as well as the temperature gradient between the casing and the conductor creating a thermogalvanic corrosion cell.

Although damaged surface casing has been mechanically repaired on numerous wells by excavation and installation of welded sleeve patches, accessing the damaged surface casing can be difficult. Inhibiting the corrosion mechanism is considered a more tenable solution.

This paper will:Provide an outline of extent of shallow external casing corrosion seen in the field;Detail the mechanisms for the external corrosion;Detail the mechanical repair procedures used to return the wells to service;Discuss possible mitigation methods to inhibit corrosion on existing wells;Discuss the treatment chosen to stop the corrosion;Provide details of the first treatments to inhibit further shallow casing corrosion.
Case Study: Modeling of a Large-Scale Tight-Gas Gathering System
Authors: Stevenson B. K. , O'Shea C. D.
Published: December 2007

This case study outlines the techniques used to model the Williams Production RMT Grand Valley gas gathering system in the Piceance Basin. The results of the modeling exemplify how a nodal analysis model can become an invaluable tool for optimizing the performance of gas gathering systems and planning future system expansion.

Field production in the Grand Valley gathering system varies minute by minute, creating a dynamic system that is difficult to model with standard practice. Using an innovative statistical method to handle the scale and complexity of the system, the model has consistently and accurately simulated the true flowing conditions of the system over the last five years. The model has been used to successfully locate and quantify substantial static and frictional pressure losses. As the field develops, proposed drilling programs are added to forecast the impact of the new wells on the system. Various pipeline and compressor expansion scenarios are tested to determine the most effective locations and cost viable options.

Recommendations from the model have been successfully implemented and have played an integral role in the expansion of the gathering system. The model has been used to identify exact locations of pressure losses, help plan for incremental drilling volumes, and quantify the additional costs incurred from third party gas entering the system.

This paper explains how a model can assist in the successful development of a large scale, high volume, and dynamic gas gathering system. Details of the modeling procedure and highlights of the innovations implemented to meet the challenging operating conditions and aggressive development of this field are presented.
Effect of Environmental Contamination on the Susceptibility of Corrosion-Resistant Alloys to Stress Corrosion Cracking in High-Density Completion Brines
Authors: Downs J. D. , Leth-Olsen H.
Published: December 2007

There has been renewed interest in the corrosivity of high-density well completion and packer fluids in recent years following a series of failures of Corrosion Resistant Alloy (CRA) tubing strings from the annular side as a result of stress corrosion cracking (SCC). It is now realised that the original corrosion testing carried out on traditional halide-based completion and packer brines may have been too cursory, and missed some important environmental factors that make CRA susceptible to SCC in these fluids. New studies have shown that some CRA become susceptible to SCC in halide brines charged with CO2 and H2S, but there remain some uncertainties about the boundary conditions that trigger the SCC.

The objective of the laboratory experiments described in this paper was to examine how the contamination of high-density brines with oxygen, chlorides and CO2 might influence the susceptibility of CRA to SCC under high temperature-high pressure (HTHP) conditions. Our results highlight the increased risk of SCC occurring in CRA tubular materials when bromide-based completion brines become contaminated with oxygen or CO2 during field use in HTHP wells. Our tests also indicate that similar contamination of formate-based completion brines is less likely to create SCC problems in CRA tubular materials in HTHP wells. We conclude that the current North Sea trend for using formate-based completion fluids in place of bromides may provide better insurance against SCC-related tubing failures.
Inhibitor Performance on Corrosion and Erosion-Corrosion Under Turbulent Flow With Sand and CO2—An AC Impedance Study
Authors: Wang C. , Neville A.
Published: December 2007

Erosion-corrosion is a severe problem in oil and gas producing wells due to high flow velocity and sand particles entrained in the system. Using corrosion inhibitors to reduce erosion-corrosion has recently been proposed as an economically viable solution for carbon steel piping systems [1]. In the literature, most studies using inhibitors to mitigate corrosion have been conducted under stagnant or low flow rate (<1 m/s) conditions. However severe erosion-corrosion may occur when inhibitor films are removed from the steel by high liquid shear forces under actual oil and gas production conditions.

The inhibiting effect of a commercial inhibitor (named inhibitor A [2]) on the behaviour of carbon steel in CO2 saturated media has been examined under high flow velocity with sand by electrochemical and gravimetric measurements. Experiments were performed using a Rotating Cylinder Electrode (RCE). The AC impedance technique was used to study the effect of inhibitor adsorption onto the metal surface. The study clearly reveals the fact that the addition of the inhibitor moves the corrosion potential towards positive values and reduces the corrosion rate. Changes in impedance parameters (Rct and Cdl) are indicative of adsorption of inhibitor on the metal surface leading to the formation of protective films.
Effect of Fracture Compressibility on Gas-in-Place Calculations of Stress-Sensitive Naturally Fractured Reservoirs
Authors: Aguilera R.
Published: December 2007

The tank material balance (MB) equation for gas reservoirs has been written taking into account the effective compressibility of matrix and fractures.

The method has direct application on stress-sensitive naturally fractured reservoirs (nfr's). Under some conditions ignoring the effect of fracture compressibility (cf) can lead to over-estimating the volume of original gas in place using a cross-plot of p/z vs. Gp. The equation presented in this paper has been developed to overcome this weakness. The use of this MB is illustrated with an example.

It is concluded that fracture compressibility can play an important role in the calculation of gas in place in naturally fractured reservoirs.

The subject matter is significant because historically formation and water compressibilities have been neglected when carrying out MB calculations of conventional gas reservoir. This assumes that these compressibilities are negligible compared to gas. The assumption implies that the reservoir strata are static. When water influx is ignored, the assumption leads to a straight line in a cross-plot of p/z vs. cumulative gas production (Gp). However, this study shows that in those instances where fracture compressibility is large, the assumptions can lead to significant error.
Numerical Studies of Gas-Hydrates Formation and Decomposition in a Geological Reservoir
Authors: Uddin M. , Coombe D. A. , Law D. A. , Gunter W. D.
Published: December 2007

Gas hydrates are a significant resource of natural gas exist both on-shore buried under the permafrost and off-shore buried under oceanic and deep lake sediments. Recent investigations consider the possibility of sequestering carbon dioxide (CO2), a greenhouse gas (GHG), in gas hydrate reservoirs and at the same time recovering the methane (CH4) from the hydrates. Numerical studies often provide an integrated understanding of the process mechanisms in predicting the potential and economic viability of CH4 gas production and CO2 gas sequestration in a geological reservoir.

This work describes a new unified kinetic model which, when coupled with a compositional thermal reservoir simulator, can simulate the dynamics of CH4 and CO2 hydrates formation and decomposition in a geological formation. The kinetic model contains two mass transfer equations: one formation equation transfers gas and water into hydrate and one decomposition equation transfers hydrate into gas and water. The model structure and parameters were investigated in comparison with a previously published model.

The proposed kinetic model was evaluated in two case studies. Case 1 was a single well natural hydrate reservoir for studying the kinetics of CH4 and CO2 hydrates decomposition and formation. Case 2 was a multi-well reservoir for studying the unified kinetic model to demonstrate the flexibility of CO2 sequestration in a natural hydrate reservoir with potential enhancement of CH4 recovery. A close agreement was achieved between the present numerical simulation and the published results. The model can be applied in the field scale simulation to predict the dynamics of gas hydrates formation and decomposition processes in a geological reservoir.
Mechanism Formations of Corrosion Damage of Inter Equipment in Wells by Continuous Scale-Inhibitor Dosing Utilizing Surface Dosing Systems: Testing Scale and Corrosion Inhibitors
Authors: Daminov A. , Ragulin V. , Voloshin A.
Published: December 2007

At the present time, Rosneft Oil Company is applying various technologies to minimize scaling problem. One of these techniques is, for example, a continuous injection of inhibitors using surface dosing systems to protect downhole equipment from damage caused by scale deposits (more than 1200 wells are equipped with dosimeters). It has been discovered that this method has some disadvantages, in particular an abnormal high rate of downhole equipment corrosion. As a result, wells are destroyed within less than a year. Our estimation shows that for some cases the corrosion rate is higher than 20 mm/year. Corrosion types and mechanisms have been determined. Corrosivity testing of the production from the above wells has been performed using coupons made of the least corrosion resistant material in the injection system, and an industrial adaptation of the material followed the examination. The corrosivity has been studied in a wide temperature and partial pressure CO2 range. Testing and selection of chemicals for corrosion prevention technologies have been carried out.
Predicting Microbially Influenced Corrosion (MIC) in Seawater Injection Systems
Authors: Maxwell S.
Published: December 2007

Many operators have encountered failures due to MIC in seawater injection systems contaminated with sulphate-reducing bacteria (SRB). In some cases, severe pitting and grooves have resulted in flowlines being abandoned or replaced. On the other hand, there are reports of little or no significant MIC in some systems, despite significant contamination with SRB being confirmed. As all the systems are of similar design, transport seawater and employ organic biocide treatments, it may sometimes seem that incidents of MIC are a case of luck rather than judgement.

A qualitative model is presented which predicts when conditions within the system will allow MIC to proceed. The model involves two phases. Firstly a biotic phase which predicts the time required for a sulphide film to develop. Secondly, an abiotic phase which considers three parameters that may stimulate the initiation of MIC pits. The model can be made semi-quantitative by introducing a constant for pitting rate. The ability to predict (even if only qualitatively) the probability of MIC under a given set of circumstances (e.g. different biocide applications, pigging programmes, etc.) during the planning stage of a seawater flood project could significantly improve the development of control strategies.

It is anticipated that the development of such models could allow a corrosion management system to predict and monitor the mitigation of MIC risk. Currently, the use of MIC risk assessment models is not widespread and most MIC monitoring, at best, estimates biocide efficacy only. Whilst biocide efficacy monitoring is an important control, it is not corrosion management.

The model allows for ongoing review of the MIC risk once monitoring data is available.
Optimization of Fracture Length in Gas/Condensate Reservoirs
Authors: Mohan J. , Sharma M. M. , Pope G. A.
Published: December 2007

We present an analytical expression for the optimum fracture length for a gas or gas-condensate well with or without non - Darcy effects in the fracture. It is shown that the optimum fracture length depends mainly on fracture conductivity, formation permeability, size of the condensate bank around the fracture, proppant volume per unit payzone thickness, and reservoir thickness. As the fracture length is increased at a fixed volume of proppant per unit thickness, the well productivity was found to go through a maximum at a particular fracture length. The analytical results are compared with results obtained from fine-grid numerical simulations using a compositional simulator, which are run for sufficiently long periods of time so that pseudo-steady state is reached. The numerical simulation results agree well with the analytical results. The analytical expressions presented can, therefore, be used as a simple method to obtain optimum fracture lengths for gas and gas condensate wells for a wide range of conditions.
Evaluation of the Proppant-Pack Permeability in Fiber-Assisted Hydraulic Fracturing Treatments for Low-Permeability Formations
Authors: Bulova M. N. , Cheremisin A. N. , Nosova K. E. , Lassek J. T. , Willberg D.
Published: December 2007

To achieve maximum production, tight-gas formations require long fractures with contained height growth. This can be achieved by using low viscosity fracturing fluids. Decrease in fluid viscosity typically leads to an increase of proppant settling rate which results in non-uniform proppant placement and reduced effective fracture conductivity. Low-density proppants can offset this effect in low-viscosity fluid, but due to their low strength can be applied only at low closure stresses and relatively low temperatures.

A new fluid system was developed especially for fracturing low-permeability formations (less than 0.01 mD). This system allows for high-strength high-density ceramic proppant to be used with reduced polymer loading and significantly decreased proppant settling rates. All these benefits are the result of adding fibers into a fluid system which create a network, helping to suspend proppant during its transport and placement into a fracture.

Laboratory studies were performed to determine the fiber's influence on long-term proppant-pack permeabilities. Retained conductivities of ceramic and sand proppant packs over the 175-250 0F temperature range were measured under various loadings and closure stress ranges. Testing has shown permeability values of the fiber-laden systems are comparable with the values for fiber-free proppant packs. A parallel study was performed on evaluating proppant settling rates in fiberladen fluids in static conditions. Fiber in a fracturing fluid system reduces the rate of proppant settling by greater than three-fold.

Special attention is paid to a proper proppant selection for hydraulic fracturing. Improper proppant selection can cause significant damage of proppant pack conductivity and minimize benefits of the fluid system.

The results prove that the innovative fiber fluid ensures uniform proppant placement within a long fracture because of fiber presence, provides conductivity comparable to pure proppant pack values, and do not have any limitations at high closure stresses.
Decoupling Damage Mechanisms in Acid-Fractured Gas/Condensate Reservoirs
Authors: Bachman R. C. , Settari A. , Walters D. A. , Rahim Z. , Ahmed M. S.
Published: December 2007

Gas condensate wells within the Khuff C formation in Saudi Arabia are typically acid fracture stimulated following drilling. Early PTA tests conducted after stimulation indicate excellent fracture conductivity and length properties. After tie - in, the wells experience a rapid production loss, which stabilizes after 2 to 5 months. Well producing BHP is below the dew point pressure. This study was undertaken to identify the source of productivity loss. Possible causes include near well liquid dropout, fracture conductivity loss and reservoir permeability loss due to increased effective stresses.

The study was successful in determining the changing total skin with time and allocating it to each of the potential damage mechanisms. This was accomplished by using a reservoir simulation model, which adequately represented stress dependent properties as a simpler function of pressure. A number of type curves were used to assist in making pragmatic decisions as to what parameters to adjust during the history matching process.
Analysis of Gas-Well Reservoir Performance Data Using B-Spline Deconvolution
Authors: Ilk D. , Anderson D. M. , Valko P. P. , Blasingame T. A.
Published: December 2007

This work presents the practical application of the recently developed B-spline based deconvolution methodology to analyze variable-rate/variable pressure drop well performance data from gas wells. As deconvolution provides the corresponding constant rate pressure drawdown response for a well/reservoir system which is affected by variable flowrates, we intend to use deconvolution of production data to identify the reservoir model and perform an analysis for estimating reservoir properties and reservoir volume.

In this work we apply our B-spline based deconvolution methodology to production pressure and flowrate history data (which are typically available on a daily or monthly basis — all field cases in this work (except Case 3) consider daily production data measurements). For this work, we apply our method using traditional gas well test data, as well as regularly measured gas well production data. We also demonstrate the appropriate handling of input data (particularly pressure test data and production data) to ensure stable/accurate deconvolution results.

The application cases in this work should be considered typical for a reservoir or production engineer, and we would expect similar performance/robustness of our methodology as it becomes a common analysis practice.

Objectives

The following objectives are proposed for this work:

To apply and extend the recent B-spline based deconvolution methodology to analyze variable-rate/variable pressure drop gas well performance data. To identify the critical issues which affect the success of deconvolution methodology when applied to production data. To state specific recommendations for practice and/or future work.
Application of a New Fracture-Injection/Falloff Model Accounting for Propagating, Dilated, and Closing Hydraulic Fractures
Authors: Craig D. P. , Blasingame T. A.
Published: December 2007

A new fracture-injection/falloff type-curve analysis method is presented for reservoirs containing slightly compressible and compressible fluids. Type-curve analysis augments conventional before- and after-closure methods, which are also reformulated in terms of adjusted pseudopressure and adjusted pseudotime to account for compressible reservoir fluids. Unlike before- and after-closure methods which only apply to specific (i.e., small) portions of the falloff data, the new type-curve method allows for analyzing all falloff data from the end of the injection through fracture closure, pseudolinear flow, and pseudoradial flow. Similar to conventional well test analysis, a satisfactory interpretation requires comparable and consistent results between the special analysis methods, before- and after-closure, and type-curve analysis.
Evaluation of the Technical and Economic Feasibility of CO2 Sequestration and Enhanced Coalbed-Methane Recovery in Texas Low-Rank Coals
Authors: Hernandez G. A. , Bello R. O. , McVay D. A. , Ayers W. B. , Rushing J. A. , Ruhl S. K. , Hoffmann M. F. , Ramazanova R. I.
Published: December 2007

Carbon dioxide (CO2) from energy consumption is a primary source of anthropogenic greenhouse gas. Injection of CO2 in coalbeds is a plausible method of reducing atmospheric emissions, and it can have the additional benefit of enhancing methane recovery from coal. Most previous studies have evaluated the merits of CO2 disposal in high-rank coals. The objective of this research is to determine the technical and economic feasibility of CO2 sequestration in, and enhanced coalbed methane (ECBM) recovery from, low-rank coals in the Texas Gulf Coast area. Our research included an extensive coal characterization program, deterministic and probabilistic simulation studies, and economic evaluations. We evaluated both CO2 and flue gas injection scenarios.

In this study coal core samples and well transient test data were obtained for characterization of Texas low-rank coals. Simulation studies evaluated the effects of well spacing, injectant fluid composition, injection rate, and dewatering on CO2 sequestration and ECBM recovery.

Probabilistic simulation of 100% CO2 injection in an 80 - acre 5-spot pattern indicate that these coals can store 1.27 to 2.25 Bcf of CO2 with an ECBM recovery of 0.48 to 0.85 Bcf. Simulation results of 50% CO2 - 50% N2 injection in the same 80-acre 5-spot pattern indicate that these coals can store 0.86 to 1.52 Bcf of CO2, with an ECBM recovery of 0.62 to 1.10 Bcf. Simulation results of flue gas injection (87% N2 - 13% CO2) indicate that these same coals can store 0.34 to 0.59 Bcf of CO2 at depths of 6,200 ft, with an ECBM recovery of 0.68 to 1.20 Bcf.

Economic modeling of CO2 sequestration and ECBM recovery for 100% CO2 injection indicates predominately negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging from $2 to $12 per Mscf and CO2 credits based on carbon market prices ranging from $0.05 to $1.58 per Mscf CO2 ($1.00 to $30.00 per ton CO2). Injection of flue gas (87% N2 - 13% CO2) results in better economic performance than injection of 100% CO2.

Moderate increases in either gas prices or carbon credits could generate attractive economic conditions that, combined with the close proximity of many CO2 point sources near unmineable coalbeds, could generate significant CO2 sequestration and ECBM potential in Texas low-rank coals.
Hybrid Fracture Stimulation in Underpressured Coals
Authors: Ramurthy M. , Lyons B. , Magill D. P.
Published: December 2007

Some of the significant strides made in coal stimulation during the last 25 years can be attributed to the development of new-generation fluid systems (i.e., low gel loading fluids with efficient low-temperature breaker systems that cause less polymer damage in coals). All these new developments were implemented to (a) minimize damage in coals, and (b) maximize production. Water fracture treatments in coals completely eliminated polymer damage but did not always maximize production. The use of new-generation crosslinked fluids did provide better half-lengths and conductivities but still left residual damage in coals. Based on production, it was confirmed that the benefits obtained with this fluid system outweighed the damage created. To further reduce the damage in coals and obtain better regained fracture permeability, implementing hybrid fracture treatments in coals was considered in this San Juan basin project. The term "hybrid" in this case refers to a water pad followed by crosslinked fluid sand stages. Potential benefits of this technique in coals include: (a) minimizing damage caused by gel, (b) maximizing regained permeability, (c) containing height growth, and d) lowering cost.

There are two parts to this work. The first part presented in this paper contains the design, implementation, and encouraging initial results obtained from the seven wells in this project, which is in an underpressured area. This is the first project in which hybrid-type treatments have been applied in a low-pressured formation. This paper will discuss the lessons learned from such an application in coals. When sufficient production data becomes available, the second part of this work will quantify the results via reservoir simulation. The second part will also include quantified results from another current hybrid fracture-stimulation project where the coals are slightly overpressured.
U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces
Authors: Walker J. A. , Ogbe D. O. , Zhu Tao
Published: December 2007

Alaska's North Slope and the United Kingdom North Sea were petroleum frontiers in the truest sense around 1960 when industry gained access to both areas. Exploration of these two petroleum provinces progressed almost simultaneously with both emerging as significant sources of oil and gas. Both provinces entered the 1960's with no oil production, but, by the end of the 20th century, the provinces combined had delivered almost 50 billion barrels of oil equivalent to markets in Europe and the United States.

Alaska's North Slope started producing oil at about the same time as the United Kingdom North Sea, in the mid to late 1970's. Alaska North Slope (ANS) and UK North Sea oil production rates were approximately equal in 1980, but UK North Sea oil production has exceeded that of the Alaska ANS by more than 40% in recent years. The UK North Sea and ANS share similar areal sizes and other similarities, but differ in several key areas including government policy. This paper examines exploration and development history, resource access, and government take for the ANS and UK North Sea petroleum provinces using information available to the public. This analysis shows that government policies and the lack of a gas market have played a crucial role in the production history of the Alaska North Slope.
Prediction of Slug-to-Annular Flow Pattern Transition (SAT) for Reducing the Risk of Gas Lift Instabilities and Effective Gas/Liquid Transport From Low-Pressure Reservoirs
Authors: Toma P. , Vargas E. , Kuru E.
Published: December 2007

Slug to annular flow pattern transition (SAT) taking place during the upward gas-liquid well transportation is a source of flow instabilities often experienced with conventional gas lifting as well as with unloading operations of water accumulated at the bottom level of gas wells in low-pressure gas or coalbed reservoirs. In order to minimize the pressure drop and gas compression work, gas lifting of relatively large volumes of fluid (oil and water) uses mainly a slug flow pattern while the production of gas with relatively small amounts of condensate or water (unloading operation) uses an annular flow pattern. In both situations, significant decreasing of tubing pressure from perforation to wellhead levels, is associated to significant increase of superficial gas velocity, may induce flow pattern transitions (usually from bubble to slugs and, further from slugs to annular).

This paper uses field data and laboratory measurements to suggest that SAT can be a source of flow instabilities and should be avoided.

Understanding and proper prediction of SAT is particularly essential for developing suitable production operations and for designing effective gas lifting or unloading strategies from low-pressure gas and oil reservoirs (including upward transportation of hot fluids resulting from steam-assisted heavy oil operations).

With depletion of existing gas reservoirs trend the need for effective gas well deliquification is in great demand.

Transportation of water produced at the perforation level (usually between 10-60 m3/d) over a vertical depth of 200 to 2000 m under low (often variable) reservoir pressure (< 50 m of water) ask for finding un-conventional and effective artificial lifting strategies. Improving the understanding of gas-liquid upward transportation mechanisms including the avoidance of instabilities induced by flow pattern transitions is essential.

This paper addresses this problem through laboratory measurements of steady and oscillatory components of flow-pressure under a broad range of gas injected rate and simulated reservoir pressures. Comparison of laboratory data with existing STA models is performed first; selected models are then tested for field situations.

Effective field strategies for avoiding the SAT occurrence using either a slug or an annular flow pattern regime under low-pressure and standard (IPR) reservoir conditions are discussed in view of practical field applications and selection of a suitable gas lifting strategy.
SSC Performance of a Super 13% Cr Martensitic Stainless Steel: Influence of PH2S, pH, and Chloride Content
Authors: Marchebois H. , Leyer J. , Orlans-Joliet B. , Deletombe P. , Langrill C. , De Montleber D.
Published: December 2007

There is an increasing demand for Super 13% Cr (Super Martensitic Stainless Steel) tubing and casing (OCTG – Oil Country Tubular Goods), due to the material's superior strength and CO2 resistance, over conventional 13% Cr steel. Super 13% Cr combines low carbon content with increased Ni and Mo content, and particular heat treatment processes, in order to achieve its superior properties. To date, the literature available on this material is limited, with most articles concentrating on the explanation and remedies to major line-pipe failures that occurred on welds.

This paper summarizes tests to assess the role of chloride content in PH2S and pH testing solution. The negative effect of H2S saturation of the solution was observed, leading to a decrease of the passivation stage of the steel. Taking into account electrochemical parameters such as current densities and corrosion potentials, various environments (pH, chloride content and H2S) where SSC is likely to occur were investigated. The influence of the three parameters led to the creation of a 3-Dimensional mapping of SSC susceptibility with regard to the use of Super 13% Cr Stainless Steels. The Fit-For-Purpose philosophy of the new edition of NACE MR0175/ISO 15156 standard was used to develop this map.
Field Experience To Assess Efficiency of Scale-Dissolver Treatment in a Subsea Deepwater Well
Authors: Daher J. S. , Gomes J. A. T. , Rosário F. F. , Bezerra M. C. , Amorim V. C. F. , Dumas G. E. S. , Oliveira E. A. P.
Published: December 2007

The objective of this paper is to present how Petrobras is successfully managing production losses due to mineral scale formation in subsea production wells from its biggest offshore field1.

Marlim Field, discovered in 1985 with a STOIIP estimated at 1,012 million STD m3 (6,369 million STB) and a field area of 146 km2 is located in water depths ranging from 600 m to 1100 m.Current Marlim Field production, around 446,754 bpd is supported by injecting 761,971 bpd of sea water. The water production is 217,150 bpd (water cut = 32%) and GOR is 82 STDm3/STDm3. A total of 117 wells are on operation, with 73 producers and 44 water injectors. The field was developed using subsea completion through the vertical, deviated and horizontal wells, equipped with cased hole and open hole gravel packed screens.

Scale formation has occurred as a consequence of the incompatibility between the barium and strontium present in formation water and the high amount of sulfate in the injected seawater.

To avoid production losses a plan of water management was implemented, including frequent produced water chemical analyses to investigate the convenience for applying a chemical bullhead treatment to remove scale in the production wells (tubing, screen, gravel pack and near well bore)2,3,4.

This paper presents results from dissolver treatments performed in the field and also from a special investigation using a rig in a horizontal well. Valuable information was obtained in this intervention, clearing up the scaling occurrence phenomena in this scenario, allowing therefore an improvement on productivity recovery of the wells.