bluuebunny/crossref_metadata_2025 huggingface dataset:
Slim Riser - A Cost-Effective Tool for Ultra Deepwater Drilling
Authors: Childers Mark , Quintero Alan
Published: December 2007

Until recently, operators have often been faced with a stark choice when planning their deep and ultra deep (over 5,000 ft) water drilling programs. They either paid the high cost of major Mobile Offshore Drilling Unit (MODU) upgrades or the high day rates associated with new, 5th Generation MODUs. Recently, the Surface BOP (SBOP) Concept appeared as an alternative with attractive advantages under certain circumstances. A third alternative is herein presented. Namely, the Slim Riser Concept that can be used to bring older 3rd and 4th Generation rigs into the deepwater arena on a favorable economic basis, but still maintain many of the advantages of the standard, Conventional 21-inch riser, 18-3/4 inch BOP subsea system.

The key features of the slim riser concept presented are:16 inch riser, which substitutes the Conventional 21 inch riser.The rig retains its existing 18 ¾ inch BOP stack and lower riser assemblies (LMRP) such as the flex joint.The rig retains its 21 inch upper riser assemblies such as the diverter, telescoping joint, etc.Several options, including a preinstalled wellhead sleeve in a conventional 18 ¾ inch housing, can be chosen to reduce the effective wellhead bore.

By reducing the riser size from 21 inch to 16 inch OD a rig’s water depth capability is improved significantly due to:Reduced tensioner loadsLower variable deck loads (VDL) requirements due to weight savings from the reduced volume of stored mud and reduced riser tensionsReduced required mud pit space due to the smaller riser volumeReduced riser storage requirements due to the smaller riser

This paper will fully explain the Slim Riser Concept including:A comparison to Conventional 21 inch riser systems and SBOP systemsA review of the 16 inch riser designBOP control system considerationsExploration of casing program considerations with slim hole drillingExploration of slim hole wellhead systems with standard 18-3/4 inch housingsExploration of mooring system considerations, including the use of conventional spread moored or taut/semi-taut line systemsExploration of guide line versus guideline-less reentry with Slim RiserField installation considerations

In addition, the paper will compare the tools available for ultra deepwater drilling including Conventional 21-inch riser drilling, drilling with SBOP and drilling with the slim riser concept. Guidelines will be presented for selecting the "right" system for the "right" application.
Novel Application of Sodium Silicate Fluids Achieves Significant Improvement of the Drilling Efficiency and Reduce the Overall Well Costs by Resolving Borehole Stability Problems in East Africa Shale
Authors: El Essawy Wael M. , bin Hamzah Rosli , Malik Mirghani Mohamed , Knox David , Monem Mohammed R. , Oswald Reinhard J.
Published: December 2007

Historically, wells drilled in East Africa and mainly in Sudan have experienced drilling related problems due to the highly reactive and dispersive shales of the Aradeiba formation. Hole instability problems have included washed out hole sections combined with tight hole and poor coring efficiency. Frequent wiper trips were required and logging of the wells was not always successful.

Over time, several conventional inhibitive water-based drilling fluid types have been used, such as KCl/polymer, KCl/lime/polymer, KCl/PHPA, and KCl/glycol, but with only marginal improvements in hole stability and drilling performance. A sodium silicate/KCl system was designed to provide the necessary inhibitive qualities. The first field trial well in East Africa was drilled with a sodium silicate/KCl system and the following benefits were observed:24% reduction in drilling daysShale drill cuttings with exhibited excellent integrityNo evidence of cuttings hydration or dispersionReduced wiper tripsCaliper logs indicated in-gauge wellboreLogging program completed as per programExcellent coring efficiencyLow filtrate invasion

This paper describes the extensive technical teamwork between the service company and the operator that led to the development and successful application of a sodium silicate drilling fluid for use in the Aradeiba stressed shale sections.

The paper includes a description of the formulated silicate fluid and test data from the extensive laboratory testing. Enhancements in drilling and coring performance over other inhibitive water-based drilling fluid systems are documented and reviewed, in particular coring efficiency (hole stability in the shale zones, elimination of core jamming) and improved core data acquisition (obtaining fresh-state core samples with minimal mud filtrate invasion).

As a result of this fluid design and application, an additional thirty wells have been drilled with the sodium silicate system in the area, including the highest temperature well ever drilled in the world with a silicate drilling fluid.
Casing Strength Degradation due to Corrosion - Applications to Casing Pressure Assessment
Authors: Sun Kai , Guo Boyun , Ghalambor Ali
Published: December 2007

Well casings are subjected to severe corrosion because of their exposure to corrosion environments – seawater, saline formation water, and the corrosive fluids that are transported. Corrosion develops pits and cavities at both the inner and outer walls of the casing. The burst and collapse loads are the most common loads for casing under operation conditions. The loads act on the pitted casing will cause stress concentration and degraded casing strength. The strength deterioration can significantly shorten the casing life; even cause failure of the well. Thus, it is highly desirable to know the stress concentration factor (SCF) for both casing designing and evaluation processes.

The degree of stress concentration depends on the cavity shape. This paper derives simple formulae for SCF around cavities of various geometries including shallow-spherical (depth is less than the open radius), exact hemispherical (depth is equal to the open radius), and deep-spherical (depth is greater than the open radius) cavities. SCF graphs are generated and results of sensitivity analyses are presented. A comparison analysis of the shallow-spherical, exact hemispherical and deep-spherical cavities SCF formulae is also presented. The analysis shows that the shallow-spherical and deep-spherical formulae give almost the same SCF results. Thus, any shallow-spherical or deep-spherical formulae can be used in designing and evaluating casing with spherical cavities. Finally, application procedure for predicting the degraded casing strength is illustrated in this paper.
Fracture Pressure Gradient in Deepwater
Authors: Rocha Luiz A. S. , Falcão José L. , Gonçalves C. J. C. , Toledo Cecilia , Lobato Karen , Leal Silvia , Lobato Helena
Published: December 2007

The majority of the petroleum engineers agree that fracture pressure gradient is one of the most important items to be considered when designing or drilling a well.

The perception of the importance of the fracture pressure gradient comes from the results of the severe economic losses that the oil industry has faced when dealing with lost circulation related problems. In the worst scenario, these problems can escalate to a blowout due to the reduction of the hydrostatic pressure in the well. In addition, lost circulation problems are likely to occur and become even harder to control if the well is in deepwater.

It is well known that a correct prediction of the fracture pressure gradient minimize drilling problems. However, the methods used by oil industry to perform this task are generally based on equations or methodologies that give questionable results and do not match actual field data.

Fracture pressure gradient methods are generally based either on equation derived from rock mechanics theories or in simplified methods. Although, the first tries to closely represent the rocks underground behavior, they are too complex and call for a number of data that normally are not available. On the other side, the second carries many simplifications and barely represents subsurface conditions. However, the last is simple to use and consequently more popular among drilling personnel. Regardless of the method, a good calibration, in general hard to be accomplished, is always necessary to provide good estimates.

Finally, performing leak off tests (LOT) is usually the procedure carried out by most of the oil companies to establish fracture pressure gradient values for a given area. Once LOT`s are obtained, they are used to calibrate simple equations or will be part of the company database to simply build fracture pressure gradient curves.

The objective of this work is to make a critical examination of the current methods used to estimate fracture pressure gradient. The work also presents simple methodologies based on leak of tests data to estimate fracture pressure gradient for a given area. Results based on actual field data to exemplify the use of the presented methodology will be shown, mostly for deepwater oilfield.
The Cement-to-Formation Interface in Zonal Isolation
Authors: Ladva H. K. J. , Craster B. , Jones T. G. J. , Goldsmith G. , Scott D.
Published: December 2007

Maintaining zonal isolation for the lifetime of oil and gas wells is critical. Leakage behind casing can reduce the cost-effectiveness of the well and cause health and safety risks from pressure build-up and contaminated aquifers. During the completion and production phases of the well, temperature and pressure variations can cause stresses at the cement-to-formation interface. The ability of the casing-cement system to maintain a seal at the cement-to-formation interface depends on the condition of the formation surface prior to slurry placement. The condition of a shale will depend upon the nature of the drilling fluid used, whereas the condition of a permeable rock will depend upon the presence and nature of the filtercake deposited during drilling and circulation.

In this paper we present an improved understanding of chemical interactions at the cement-to-formation interface and the factors that determine bond strength and the position of the plane of failure. For permeable formations, the role of the mud filtercake for different mud types is explored. For nonpermeable formations, the presence and effect of a residual mud film are also examined. The extent and depth to which chemical alteration of the mudcake occurs when in contact with cement are determined, together with measurements of the yield stress and water content profile of the altered mudcake. The effect of exposing swelling and nonswelling shales to inhibitive drilling fluids on bond strength is presented. Laboratory-scale test equipment and a small-scale wellbore simulator, developed for tests under realistic field conditions, are described. The flexibility of cement plays a role in bonding and is demonstrated by the simulator tests. This improved understanding allows us to confirm the key issues at the cement-to-formation interface and propose some solutions for effective zonal isolation.
Lightweight Cement Slurries Using Multifunctional Liquid Additives: A New Approach to Offshore Well Construction
Authors: Kamolchai Pattanapong , Keittipong Kaotun , Jeff Hibbeler , Phil Rae
Published: December 2007

Proposal

Recent technical and logistical challenges in the Gulf of Thailand have driven the development of a new approach to lightweight cementing. The industry has evolved from numerous and complicated dry cement blends being used on 45-day well constructions to the present minimum liquid additive, lightweight, single slurry approach used on 5-day wells. As nearly all wells are now slimhole monobores, the cement job has become one of the most important operations in the life of the well. The absence of packers or other isolation devices means that the cement job functions as a primary pressure barrier and is the only technique to isolate the numerous sands in each well. This combined with the logistic issues of fast offshore batch drilling exact a premium on cementing products and the entire cementing process itself.

For offshore applications it is advantageous to use an all-liquid system so as to avoid relying on mud pits to blend mixwater, to avoid the confusion of multiple dry blends in the field and to have flexibility to make last minute changes in slurry design. Recently a new approach to lightweight cementing using Multifunctional Liquid Additives (MLA’s) was developed so that on-the-fly mixing is possible with only three to four streaming additives. MLA’s have reduced what used to be a complicated set of dry blends to a few liquid additives. By simply adjusting the cement:water ratio and MLA concentration, the same base slurries can be tailored for nearly any scenario. This approach has been used recently in PTTEP’s Arthit gas field to construct a 1.60 SG. production string slurry at 190°C. The same additives work for shallow gas where temperatures are over 150°C cooler. Because the systems are so robust, slurry charts have been implemented such that the rig can decide what slurry to pump based on a given bottom hole circulating temperature (BHCT) and desired thickening time.

This paper illustrates the various ways lightweight slurries using MLA technology have created a new approach to offshore well construction in The Gulf of Thailand.
Maximizing Production with 13Cr Solid Expandable Tubulars in Sarawak Gas Fields
Authors: Bada Inyau , Maekiaho Leo , Ain Fitzerald Mathew , Nijveld Erik , Tan Ivan , Book Larry , Dubedout Laurent
Published: December 2007

Solid expandable tubular technology presents an opportunity to significantly boost the production capacity of wells by increasing the size of the completion. As such, it offers an economically attractive and environmentally friendly option to breathe new life into gas fields. It is flexible in its application, and can be applied fast to react quickly to changes in future gas demand. It makes effective use of existing surface facilities, and does not affect abandonment costs.

This paper describes the planning and installation of the world's first 7-5/8" 13Cr (13% Chromium) solid expandable tubular workovers in the F23 gas field in Sarawak. A significant amount of development work, modelling and testing was done to deliver components required for the installation. The solid expandable tubular workover resulted in an increase of 50% in well capacity for one of the wells of which the production results were known at the time of writing this paper.
Experimental Determination of the Variation of Torsional Resistance of Mudcakes with the Variation of Mud and Mudcake Composition
Authors: Amanullah Md.
Published: December 2007

Torque and drag problems are major operational problems in deviated, horizontal and extended reach wells. Hence, management of torque and drag resistance of mudcakes as low as possible is an important design consideration for a superior mud design for horizontal and extended reach wells.

Several mudcakes of variable compositions were tested using a newly developed test facility. The results indicate that the torsional resistance of mudcakes is strongly influenced by the physics and chemistry of the mud additives. Fresh water-based bentonite mudcake gave the lowest torsional resistance and starch containing salt water based NaCl-bentonite mudcake gave the highest torsional resistance. The presence of salts, especially salts containing divalent and larger hydrated ionic diameter cations dramatically increases the torsional resistance of bentonite mudcake. The drilling engineering implication of this observation is that salt contamination of bentonite mud may turn the mudcake more shear resistant and thus expected to create higher torque and drag problems. The presence of barite in a fresh water based bentonite mud also increases the shear resistance of the mudcake. Hence, mudcake deposited by a weighted bentonite mud is expected to cause increased torque and drag problems. The contamination of bentonite mud by cations of smaller hydrated ionic diameter (KCl salt) causes a smaller increase in torsional resistance compared to the presence of cations of larger hydrated ionic diameter (NaCl and CaCl2 salts). The presence of anionic CMC (carboxy-methyl cellulose) in NaCl-based salt water mud caused negligible changes in the torsional resistance of the mudcake. However, the presence of polyanionic cellulose (PAC) in the mud caused a significant reduction in the torsional resistance of salt water-based mudcake. The drilling engineering significant of this observation is that the fluid loss additives like PAC is more suitable for deviated, horizontal and extended reach drilling to minimise the torque and drag problems.
A Technical Evaluation of a CO2 Flood for EOR Benefits in the Cooper Basin, South Australia
Authors: Bon J. , Sarma H. K.
Published: December 2007

This study evaluates reservoir and reservoir fluid parameters relevant to CO2 flooding to enhance hydrocarbon recovery from a Cooper Basin oilfield (Field A), located in South Australia.

Field A is a tight (k<1mD) sandstone reservoir containing volatile and low viscosity oil. CO2 could be separated from raw gas produced from a nearby gas field (Field B) or made available from a gas processing facility located some 60km from Field A. The costs of preconditioning the CO2 to suitable composition and pressures are known to be high, but have not been considered in this study.

Laboratory experiments were conducted using both pure carbon dioxide and a synthesized gas derived from Field B gas, consisting mainly of CO2 and methane. The increase in oil recovery as a function of pressure was determined, which would be a basis for selection of injection pressure. In addition, minimum miscibility pressures using both CO2 and the synthetic gas mixture and the utilization factor of CO2 injected to oil produced were also determined.
High Concentration Polymer Flooding is Successful
Authors: Yang Fulin , Wang Demin , Yang Xizhi , Sui Xinguang , Chen Qinghai , Zhang Lei
Published: December 2007

Recently, new evidences show that the recovery factors of both partially hydrolyzed polyacrylamide (HPAM) and xanthan gum (XA) flooding increase with higher concentration and higher viscosity. However, when the incremental oil recovery of XA flooding in artificial cores reaches about 8.6% OOIP (original oil in place), the displacement efficiency of XA flooding levels of, but an incremental oil recovery of more than 20% OOIP can be obtained from HPAM flooding with a high concentration, the higher the concentration the higher the recovery, the recovery does not level of. The difference in recovery between the two solutions is due to the visco-elastic properties of HPAM. The visco-elastic property of HPAM fluid not only increases the volumetric sweep efficiency but also the displacement efficiency of the pay zone on a micro scale. A novel method has been developed to enhance the oil recovery in highly heterogeneous and high permeable reservoirs. The results on artificial cores with a Dykstra-Parson Coefficient of 0.72 show that an incremental recovery over water flooding of more than 20% OOIP can be obtained by early time injection of the high molecular weight, high concentration polymer solution, the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost.

In Daqing Oil Field, a pilot test of high concentration polymer injectivity was conducted on 6 injection wells in August 2002. Three wells are injecting in high permeable pay zones and the other 3 wells in low permeable pay zones. The range of effective permeability (Keff) of the pay zones is 0.354 ~1.06 um2. The results show that high permeable formations (Keff>0.890um2) are suitable for continuous injection of high concentration polymer solutions (concentration 2,000 ppm ~2,500 ppm, molecular weight 17 million Daltons, viscosity 200~250 mPa.S). There were 22 oil wells around the 6 dispersive polymer injection wells. In February 2004, the average fluid production of each well was 90.2 tons per day, the average daily oil production of each well was 21.7 tons and average water cut was 79.5%. Compared to low concentration (1,000 ppm) solution flooding, the fluid production per day of each well remained and the daily oil production of each well increased by 3.4 tons (an increase of 18.6%) and the average water cut decreased by 1.0%.The average water cut decreased by a maximum of 7%.The results show that the injection of high concentration polymer fluid is very effective and the pilot area will be further expanded.
Field Implementation of Alkaline-Surfactant-Polymer (ASP) Flooding : A maiden effort in India
Authors: Pratap Mahendra , Gauma M. S.
Published: December 2007

The Viraj oil field lies in Ahmedabad-Mehsana tectonic block of Cambay Basin in India. The field has been under exploitation for the last nearly two decades and produces 18.9°API oil from the sandstone reservoir with an average porosity of 30%and permeability ranging from 4.5 to 9.9 Darcy. Reservoir temperature is 81°C and initial reservoir pressure is 135 kg/cm2. Ultimate oil recovery estimated from the field, producing under active water drive, is 32 % of OIIP.

After analyzing the rock and fluid properties, extensive laboratory studies were undertaken on native cores by R & D institute of ONGC to evaluate the efficacy of Alkaline – Surfactant – Polymer (ASP) process in Viraj field. Laboratory studies indicated an incremental oil recovery of 18 % of OIIP over water flood. On the basis of these encouraging results, a pilot was designed with four inverted 5-spot patterns. Facilities have been created to ensure proper dosing of chemicals, optimum fluid injection and monitoring of injection fluid quality. A comprehensive data-acquisition strategy has been adopted right from the beginning. First phase of the pilot i.e. injection of Pre-flush and ASP slug(20 % PV) having composition of 1.5 wt.% alkali, 0.2 wt % (100% Active) surfactant and 800 ppm anionic polymer have been completed.

This paper aims to present salient features of the laboratory findings and the ASP pilot in progress. The data generated during the first phase of the pilot analyzed and presented in this paper shows encouraging results. Final evaluation of the pilot is, however, planned after completion of the targeted ASP/Polymer/Chase water injection.
Elasticity of HPAM Solutions Increases Displacement Efficiency under Mixed Wettability Conditions
Authors: Xia Huifen , Wang Demin , Wu Junzheng , Kong Fanshun
Published: December 2007

In this paper, the rheological characteristic of HPAM solutions is studied and the oil displacement efficiencies of viscous-elastic HPAM solutions (concentration in series) and viscous glycerin solutions (no elasticity, viscosity in series) are studied by flooding at visual microscopic glass models and artificial cores. Also, the effect and mechanism of the viscous-elastic behavior of HPAM solutions and glycerin solution on the displacement of residual oil films under mixed wettability conditions is studied, the relationship between the elastic behavior of HPAM and oil displacement efficiencies is given. The results of rheological characteristic measurement indicate that both the viscosity and the first normal stress differential (N1) of HPAM solutions increase with the increase in concentration, HPAM solutions show strong viscous-elastic characteristics under high concentration conditions. The results of microscopic oil displacement experiments indicate the displacement efficiencies of HPAM solution flooding and glycerin solution flooding gradually increase with the increase in the viscous-elastic behavior of HPAM solutions and the viscosity of glycerin solutions. However, for HPAM solution flooding, the displacement efficiency is always higher and residual oil saturation lower than that of glycerin at the same viscosity and same capillary number. Last, the displacement experiment in artifical cores is conducted and the similar resultes are validated.
Prediction of Residual Water Saturation Using Genetically Focused Neural Nets
Authors: Ibrahim Mohd Azizi , Potter David K.
Published: December 2007

The "genetic petrophysics" approach for predicting petrophysical parameters using genetically focused neural nets (GFNN) has only recently been introduced. The approach only requires a minimum number of core plugs, along with associated wireline log data, from a chosen representative genetic unit (RGU). This case study has successfully developed and tested this new methodology to predict residual water saturation.

Combinations of wireline logs and core data from a short 7m RGU interval in a North sea well were used to train the GFNN predictors. These were then applied to predict the residual SW throughout the whole logged section in the training well and adjacent wells in the same field. Traditional hydraulic unit analysis provided the basis for selecting the minimal training plugs. Only 4 core plugs were finally required to represent the hydraulic units in the RGU and provide good results. This approach is very cost effective in terms of core material and computing time.

Presently we have only tested this approach in oil bearing shoreface reservoirs. Thus, it is recommended that this approach be tested in other environments.
Comparative Simulation Study of Water Flood
Authors: Li Dacun
Published: December 2007

Proposal

Secondary oil recovery led by water flood accounts for one half of the oil recovered in the United States. In addition, streamline simulation is becoming more and more popular these days due to its higher speed compared with finite-difference method. In this paper, a streamline simulator is developed for water flood based on analytical and numerical methods. Oil recovery and water cut from the streamline simulator are compared with their counterparts from a finite-difference simulator. In addition, a practical method to implement an extremely large time step in streamline simulation is introduced. Results show that numerical dispersions decrease from finite difference method, to numerical streamline method, and to analytical streamline method. For numerical method, numerical dispersions decrease with increased time step size. By using the new practical method, the streamline simulation can be greatly sped up. The streamline simulator can be run by using an extremely large time step, in which 0.13 pore volume of water is injected. About 10 time steps are needed for simulating the 1.2 pore volume injection of water.
Determination of Oil in Place, Ratio of Initial Free Gas to Oil, Reservoir Rock Properties from Limited Pressure Data
Authors: Ojo Kolawole P. , Djebbar Tiab , Osisanya Samuel O.
Published: December 2007

This study presents a pressure transient analysis technique for determining the initial oil-in-place and the ratio of initial gas to oil, within the drainage area of the test well. The method is based on a combination of the material balance equation, the cumulative production history, individual well rate history and PVT data of the reservoir, with limited well test pressure data. The solution method considers the variable rate production history of each of the wells and combines this data with a global pressure data analysis approach as opposed to the usually employed approach of applying each method in isolation, which often produces erroneous results.

The analysis procedure allows every detail of the reservoir development, rate changes at every well from inception, global (reservoir wide) and local (individual well) fluctuations in pressure to be included in the overall results. Local variations in reservoir rock properties at the well locations are also accommodated in the method. By modifying the analysis technique used for solving the linear material balance, a method is derived that allows the simultaneous determination of the original oil-in-place, and the initial ratio of free gas to oil in the reservoir, without the previous knowledge of one or the other from an independent source, a requirement that is often needed for such solution. A Dynamic Material Balance Program (DMBP), a Visual Basic based program, was developed to implement the solution procedure presented in this paper.
Dynamic and Static Fluid Loss Properties of Novel Starches Prepared using Reactive Extrusion Technique
Authors: Amanullah Md. , Yu Long
Published: December 2007

Several novel fluid loss additives have been developed using agricultural resources grown in Australia. The fluid loss controlling performance of the novel mud additives were evaluated and compared with the fluid loss controlling performance of a widely used modified starch. The evaluation of the effect of starch concentration on the fluid loss behaviour of water-based muds indicates a working concentration range of 2-8 ppb for most of the novel starch products for different level of fluid loss control. Experimental results indicate that some of the newly developed starches show static and dynamic fluid loss characteristics similar to or better than the static and dynamic fluid loss characteristic of a widely used modified starch used by the mud industry. The static fluid loss properties measured after thermal treatment at different temperatures indicate that the newly developed starch products can be used as fluid loss additives for drilling boreholes having bottom hole temperature up to 150°C. The dynamic fluid loss property of the novel starches measured at 80°C thermal condition indicate that the newly developed products have similar or better dynamic fluid loss control properties than the currently used modified starch.
A New Relationship of Rock Compressibility with Porosity
Authors: Li Chuanliang , Chen Xiaofan , Du Zhimin
Published: December 2007

This paper presented a new relationship of rock compressibility with porosity, which is a new formula deduced after a theoretical study of mechanics of porous media. The new formula of this paper incorporates two parameters of rock: the elastic modulus and the Poisson&s ratio, which are easier to measure in laboratory than compressibility itself. According to the new formula of this paper, rock compressibility increases as porosity increases, while the conventional empirical formula displays the reversal. The new formula also shows that rock compressibility depends on the rigidity of rock skeleton. According to the new formula of this paper, compressibility of rock in normal range of reservoir porosity is quite smaller than that of reservoir liquids, while the conventional empirical formula tells that compressibility of rock is usually larger than that of reservoir liquids. The new formula can explain many phenomena that the conventional empirical formula can not and can also provide correct values of rock compressibility for reservoir engineering research.
Optimized Exploitation of Gas-Condensate Reservoirs Using Neuro-Simulation
Authors: Ayala Luis F. , Ertekin Turgay , Adewumi Michael
Published: December 2007

Gas-condensate reservoirs have been the subject of intensive research throughout the years as they represent an important class of the world's hydrocarbon reserves. Their exploitation for maximum hydrocarbon recovery involves additional complexities that cast them as a different class of reservoirs - apart from dry-gas and black-oil reservoirs. Gas-condensate reservoirs are good candidates for compositional simulation studies as their depletion performance is highly influenced by changes in fluid composition. Often times, highly sophisticated and computationally intensive compositional simulations are needed for the accurate modeling of their performance, phase behavior, and fluid flow characteristics. The desirable outcome of a simulation study for gas condensate reservoirs is the identification and development of the best operational production schemes that maximizes hydrocarbon recovery with the minimum loss of condensate at reservoir conditions. However, compositional simulations are demanding in terms of computational overhead, manpower, and software and hardware requirements. Artificial neural network technology (soft-computing) has proven instrumental in establishing expert systems capable of learning the existing vaguely understood relationships between the input parameters and output responses of highly sophisticated hard-computing protocols such as compositional simulation of gas-condensate reservoirs. In this study, we conduct parametric studies that identify the most influential reservoir and fluid characteristics in the establishment of optimum production protocols for the exploitation of gas-condensate reservoirs. During the training phase of the artificial neural network, an internal mapping that accurately estimates the corresponding output for a range of input parameters is created. In this paper, a powerful screening and optimization tool for the production of gas-condensate reservoirs is presented. This tool is capable of screening the eligibility of different gas-condensate reservoirs to exploitation as well as assisting in designing the optimized exploitation scheme for a particular reservoir under consideration for development.
Determination of Gas Permeability of Tight Reservoir Cores without Using Klinkenberg Correlation
Authors: Li Shuliang , Dong Mingzhe , Dai Liming , Li Zhaowen , Pan Xuefeng
Published: December 2007

This paper reports the laboratory measurements of gas permeability for tight reservoir core samples with various upstream, downstream, and average pressures. Measurements are conducted with backpressures from atmospheric pressure up to 9.3 MPa. It is found that exerting a backpressure at the outlet of the core sample can effectively reduce the gas slip effect and improve the permeability measurements. When the backpressure reaches a certain level, defined as the minimum backpressure, the gas slip effect can be eliminated so that non-slip gas permeability can be obtained without using Klinkenberg correlation. When the backpressure exceeds the minimum backpressure the measured non-slip permeability is a constant for a given core sample. From this finding, a method of directly determining gas permeability of tight reservoir cores is provided. The experimental results also indicate that the minimum backpressure increases with decrease in permeability of tight reservoir cores. The concept and technique can be applied in the measurement of effective/relative gas permeability in multiphase systems where Klinkenberg correlation cannot be used to correct the gas slip effect.
Reservoir Porosity and Permeability Estimation from Well Logs Using Fuzzy Logic and Neural Networks
Authors: Lim Jong-Se , Kim Jungwhan
Published: December 2007

Petroleum reservoir characterization is a process for quantitatively describing various reservoir properties in spatial variability using all the available field data. Porosity and permeability are the two fundamental reservoir properties which relate to the amount of fluid contained in a reservoir and its ability to flow. These properties have a significant impact on petroleum fields operations and reservoir management. In un-cored intervals and well of heterogeneous formation, porosity and permeability estimation from conventional well logs has a difficult and complex problem to solve by statistical methods. This paper suggests an intelligent technique using fuzzy logic and neural network to determine reservoir properties from well logs. Fuzzy curve analysis based on fuzzy logics is used for selecting the best related well logs with core porosity and permeability data. Neural network is used as a nonlinear regression method to develop transformation between the selected well logs and core measurements. The technique is demonstrated with an application to the well data in offshore Korea. The results show that the technique can make more accurate and reliable reservoir properties estimation compared with conventional computing methods. This intelligent technique can be utilized a powerful tool for reservoir characterization from well logs in oil and natural gas development projects.
An Innovative Approach to Assessing Miscible Flooding in a North African Field
Authors: Thompson Maggie , Bird Peter
Published: December 2007

This paper describes an innovative approach to assessing the viability of an EOR scheme in a sedimentary sandstone reservoir and making strategic decisions regarding the field development. The study involved: a series of workshops involving all disciplines of the operational team, EOR experts and facilitators; screening studies to identify the most likely EOR processes for the field; detailed sector and full field modelling; value modelling; and the construction of a decision risk model incorporating results from all stages of the assessment to provide a tool that the operator can use to make complex decisions. This paper concentrates on the initial workshop, detailed simulation modelling and the decision risk modelling.

The initial workshop gathered knowledge from all disciplines and set objectives and actions for the project.

A miscible gas injection project has been simulated at three different levels of detail. The finest model incorporates the very detailed geology associated with festoon cross bedding. The next level of modelling concentrates on a sector from a selected region between two wells incorporating explicit shale and channel features to ensure accurate modelling of gas flow mechanisms. Finally a full field model was constructed to honour the flow mechanisms observed in the fine scale modelling.

The decision risk model includes both "soft" and "hard" data. It incorporates the experience of the whole asset team and is able to investigate a range of different options and decisions. Production profiles from the simulation models are incorporated and algorithms are used to generate profiles for scenarios not investigated through simulation. The model can assess the value of a range of different field options taking due account of the risks and benefits.
Onsite Treatment of Oily Drilling Waste in Remote Areas
Authors: Barnes Gary R.
Published: December 2007

There are many examples of remote areas where oilfield drilling is undertaken Western Site Technologies Inc. (WST) has had experience in many areas world wide, however our main scope of treatment has taken place in the Northern Alberta and the North West territories regions of the Alberta Petroleum basin.

The Alberta petroleum basin is mature and any new prospects explored by Western Canadian companies tend to be located in areas and formations that represent difficult drilling conditions. An example of this situation is the active Belly River play, with its sensitive shales. Advanced recovery methods in mature fields often involve horizontal or inclined holes, particularly in the heavy oil regions.

To overcome excessively tight holes, avoid stuck pipe, avoid excessive hole caving and drill string drag problems, the use of oil-based mud has become more widespread than at any time in the past.
Improved Procedures for Estimating the Erosional Rates in High Offtake Gas Wells: Application of University of Tulsa Flow Loop Derived Correlations
Authors: Terziev Ivo , Taggart Ian
Published: December 2007

High rate offtake gas and gas condensate wells require both hydraulic and erosive issues to be addressed. The erosional aspects are particularly difficult and require special attention in high velocity areas if solid particles are present.

In the past, industry has attempted to handle the problem through API-RP14E, however; this standard has been widely accepted as conservative and physically unsound when applied to gas or gas condensate fluids, because it does not account for solid particle impingement. Since then, numerous models and correlations have been developed to predict wear rates in various tubing configurations.

The Tulsa work appears most comprehensive but there is little published information on how to apply many of its findings and present the results of erosional calculations in a form suitable for well design and field development planning.

This paper uses the Tulsa erosional work and presents a consistent methodology for predicting and displaying the erosion rates in a number of high offtake big bore well designs when solids production and liquid loading are present. The ideas and procedures developed here can be used with other wear estimation methods. The use of tolerable erosion (or sand) rate strategy as opposed to previously adopted (and widely used) "maximum solids free rate" approach is advocated.

The difficulties with prescribing the C constant in API RP14E are discussed and alternative derivations based on friction factors are presented. Subsequent sections consider examples of alternative gas well design, some of which use big bore technology, to demonstrate an application of a staged design process. The stages cover hot spot analysis, wear estimates and required erosional allowances before proposing an operating/monitoring strategy.
Simulation Investigation of the Feasibility of Simultaneous Hydrogen Sulfide-Water Injection to Improve Oil Recovery
Authors: Shedid Shedid A. , Abed Abdulla A.
Published: December 2007

Over the past several years, considerable attention has been devoted to the dangers of hydrogen sulfide during different phases of the oil industry, including drilling, completion, work-over operations, processing and transportation. These dangers are well understood and have been the subject of numerous field case histories and scientific studies. On the other side, a little or almost no attention is devoted to investigate the possible positive applications of hydrogen sulfide in the oil industry as an injectant to improve oil recovery.

A variety of techniques have been used to improve oil recovery from reservoirs in which there is no longer oil flow by natural forces. Water and/or gas injection(s) have been used successfully to improve the oil recovery of depleted reservoirs. The major goals of this simulation study are to investigate the feasibility of water, sour gas, and simultaneous hydrogen sulfide-water injection into oil reservoirs to improve oil recovery. Furthermore, the influences of water injection rate, hydrogen sulfide concentration and applied gas injection rate on oil recovery are studied. To achieve these purposes, a three-dimensional simulation model was developed using actual field data of an oil field in the United Arab Emirates. This simulation model was used to test the feasibility of simultaneous hydrogen sulfide-water injection to increase the oil recovery.

The results indicated that injection of water, or sour gas (hydrogen sulfide), or simultaneous hydrogen sulfide-water into oil reservoir increased oil recovery. This increment in the oil recovery due to hydrogen sulfide and/or simultaneous hydrogen sulfide-water injections were attributed to higher molecular weight of hydrogen sulfide in comparison to methane and increment of reservoir potential. The increase of gas concentration and/or injection rate increased the oil recovery. The application of the suggested technique is expected to increase oil recovery and also maintain reservoir pressure.
Intelligent Technology, Well Management Miracle - Fact or Fantasy
Authors: Davies John , Birch Bill
Published: December 2007

Despite the very substantial sums invested in its development during recent years, and in spite of the fanfares heralding its arrival, the uptake of "intelligent" or "smart" well technology, particularly the so-called "high end" devices, has been sluggish at best. If the claims made by the suppliers are to be believed, it would appear that the main reasons for this poor uptake are risk aversion and/or lethargy amongst the Operators.

This paper challenges these assertions, suggesting alternative reasons why interest remains muted, but also proposes potential solutions. Although risk aversion is almost certainly a contributory factor, the primary contention is that the market was never properly researched, or understood (value and cost drivers), and thus the wrong technology may have been developed and promoted. Why this might have happened is open to conjecture; however ineffective customer engagement at the outset, resulting in a misalignment in terms of required functionality, incompatibility with new generation well designs or simply that the development of this technology happened too late, are all postulated as possible causes.

Whatever the reasons, the ability to remotely monitor and control wells, and individual intervals, remains a key enabler for the optimal, economic development of many assets. However, unless measures are taken by suppliers to fully understand the market, and develop equipment with the appropriate functionality, it is likely the technology will remain niche and have minimal long term industry impact. On a brighter note, it is believed that new generation concepts are emerging that, if exploited coherently, have the capability of unlocking the value that the first generation technology was expected to deliver.

The purpose of this paper is thus not to stifle technological innovation, but to challenge the value of the current intelligent well toolbox, and promote potential alternatives that have higher value to both Vendor and Operator.
The Planning and Installation of a Hydraulically Operated (Intelligent) Completion - Offshore NW Australia
Authors: Guatelli Victor J. , Lay Kevin R.
Published: December 2007

In February 2004 a hydraulically operated completion was installed in the Scindian-4 well offshore North Western Australia. The completion design allows the Operator, BHP Billiton Petroleum (BHPB) to selectively produce two separate reservoir intervals without the requirement for a rig based intervention into this subsea well.

The Scindian-4 completion represents the first use of this technology (often referred to as Smart Well or Intelligent Completion) in Australia although BHPB operates a number of other intelligent wells elsewhere in the world.

This paper details the design, planning and execution of the subsea completion and covers lessons learnt during the installation phase. Particular emphasis is placed on how the completion was designed to achieve its goals and how the technology was incorporated into the existing infrastructure of this mature field.

The installation of the Scindian-4 completion will help optimise production from the field and facilitate the acceptance and use of this technology in future projects.
Decisions and Uncertainty Management: Expertise Matters
Authors: Malhotra Vinod , Lee Michael D. , Khurana Ashok
Published: December 2007

The oil industry loses an estimated US$30 billion or about 25% of its annual upstream expenditure due to poor decision outcomes1. This provides a strong incentive to study decision improvement initiatives. While there has been a significant improvement in decision-making, it has been slow and in small steps. Perhaps a paradigm shift maybe necessary to cope with an environment that is likely to become even harsher in future. We believe industry decision experts have overworked the technical and economic factors while largely ignoring individual expertise, which is the third key factor in improving decision-outcomes under conditions of uncertainty in the real world environment. Most failure stories can be largely ascribed to the lack of application of appropriate expertise in judgements. This paper questions the common industry practice of placing decision-making responsibility according to organizational hierarchy rather than expertise. In this first part of a continuing study, relying on two experiments, the paper illustrates two points. First, that decision-makers invariably superimpose their experience and expertise onto the results of normative tools and adjust them. This makes it imperative that they possess the requisite expertise. Secondly, we argue it is possible to develop a methodology to distinguish experts from intermediates and novices in the oil and gas industry. We assert that while years of experience help build expertise, by itself it is an unreliable indicator of the level of expertise.