bluuebunny/crossref_metadata_2025 huggingface dataset:
Design and Implementation of a Horizontal Injector Program for the Benchamas Waterflood - Gulf of Thailand
Authors: Graves K. S. , Valentine A. V. , Dolman M. A. , Morton E. K.
Published: December 2007

The Benchamas Development in the Gulf of Thailand is an oil play in a predominantly gas-condensate region. This development is unique in that the operator has significant oil reserves of high pour-point crude in several zones. Some zones have gas caps; others don't. Column heights are variable. The project is being developed as a waterflood with horizontal and monobore producers and injectors. The initial phase of horizontal producers were completed with sand exclusion capability, consisting of multilayerd sintered screens. This has so far proved to be effective.

The Benchamas Waterflood project is comprised of eight stacked, compartmentalized, sandstone reservoirs. These sandstones are fluvial channels and are discontinuous. The waterflood is designed to maintain oil viscosity and gas cap location to maximize recovery. The economic impact of this waterflood is estimated to increase the recovery from an estimated 12-18% (primary) to 25-35% (secondary) of the OOIP.

During the design stage of the waterflood project, simulation indicated that some horizontal injector wells would be required to enable the required injection rates. Three horizontal injectors were therefore planned. The drilling, completion, and clean up of these wells presented the Benchamas Asset Team with a series of unique challenges.

Rock mechanics analysis was conducted in the decision process to address the need or lack of need for sand control. Results will be discussed.

Drilling fluid and flow back aspects of the wells were carefully examined in order to avoid some of the problems of horizontal injectors drilled in other parts of the world by the company. An extensive literature search revealed that the laboratory work required to adequately address the issues comprehensively had not been done. The company and the fluids vendor collaborated to conduct the laboratory tests that were required to determine the correct combination of fluids and clean up procedures necessary to successfully install these wells.

This paper will highlight the unique design challenges presented to the Asset Team, discuss the efforts that were undertaken to address these challenges and the results, and present the field results of the drilling, completion, clean up, and final injection results.
Integrated 3D Geological Data into Fluid Flow Model Improves Reservoir Management Plan: Serang Field Case Study
Authors: Sukerim Waryan , Vo D. T. , Stites Jim , Swanson Mark
Published: December 2007

This paper presents a field case study describing how 3-D geological data are used in reservoir simulation to improve performance forecast and help optimize the development of the Serang Field, East Kalimantan, Indonesia.

The Serang field consists of complex stacked fluvial and deltaic channel sands under a large gas cap and over a strong aquifer. Development of the field is a challenge with the reservoir heterogeneity nature of the sands and the dynamic movement of fluid flow. Reservoir management is even more difficult as the originally thick oil columns have now become thinner with long-term production as adding infill wells or planning workovers require more accuracy for target locations. The study demonstrates the workflow involved in integrating the 3D geological data for constructing a reservoir model for field management. The model constructed helps explain the reservoir fluid flow behavior, identify by-passed oil under reservoir heterogeneity, plan for infill locations and workovers and long-term development strategy of the field. It shows the key benefits include a faster work process of building a reliable model that accounts for crucial heterogeneity, flexibility in varying reservoir properties with new data, and quicker history matching of the production data. These allow for quick turn-around to evaluate multiple development plans while improving production forecast.

The paper also discusses the practical and operational use of the model results in planning, implementing and operating wells for optimizing oil and gas recoveries.
New Technique Prevents Proppant Flowback and Improves Fracture Conductivities
Authors: Di Lullo Gino , Rae Phil
Published: December 2007

Flowback of fracturing proppant during production is a common problem. The consequences of this can be extremely serious. Loss of fracture conductivity can occur due to reduced width, which can be further compounded by partial plugging of the pack by proppant fines. The latter are produced by non-uniform loading on the proppant with resultant failure and crushing. The produced solids can wreak havoc with both downhole and surface equipment, eroding chokes and nipples, plugging flow lines and filling separators. In the case of subsea wells, the problems are even greater and can compromise well security. Since the 1980's, the standard solution applied for prevention of proppant flow back has been the use of curable resin coated proppant. While this approach has met with some success, it is far from perfect. The use of RCP's can cause fluid compatibility problems and can interfere with well clean up. Such problems have prompted resin manufacturers to modify their products and have also opened the door for the introduction of new technologies. Newer developments have included the use of small fibres to try to bind the proppant pack together or heat-sensitive plastic film to partially encapsulate clusters of proppant. These materials have reportedly been used with some success but concerns have been raised with regard to their effect on fracture conductivity, amongst other things.

This paper describes the current methods in use and presents a new system that actually enhances fracture conductivity and minimises embedment and width-loss, while simultaneously helping prevent proppant back-production.
Coaly Sandstones: Reservoir Evaluation Problems and Solutions
Authors: Souvick Saha , Corbin Steve
Published: December 2007

In fluvio-deltaic sediments of East Kalimantan, Indonesia, coal commonly occurs and poses serious problems in reservoir evaluations. Thick coal seams can easily be identified, but it is often difficult to identify and quantify coal within sandstones using the conventional well logs. This can lead to inaccurate computation of reservoir parameters such as porosity, permeability and water saturation. In this paper, it is shown how petrophysical interpretation can identify these coals and improve decision making.

In order to understand the "coaly" response on well logs, a number of core slabs were studied. It was found that the coal within the sandstones mostly occurs as thin layers interbedded with sands, not "dispersed" as often thought.Previous petrophysical analyses were reviewed where coals were not interpreted properly and resulted in over and under-estimation of coals. The new petrophysical model (ElanPlus) is based on local knowledge and extensive core data, and overcomes earlier problems. Also, the application of new logging technology (Combinable Magnetic Resonance CMR) validated the new petrophysical model and a better insight was gained. Uncertainty in quantification of coals under unfavorable situations such as, hole wash out and lack of log resolution, is now better understood.

The new petrophysical interpretation accurately quantifies coals from the conventional well logs and addresses the long standing problem in East Kalimantan sandstones. Accurate reservoir parameters can be computed and better decisions on completions can be made.
Effective Slimhole Cementing in a Challenging Environment - A Gulf of Thailand Case History
Authors: Gilmore Todd , Harrison James , Pathanakitchakarnjaroen Duantem , Chanpen Chakrit
Published: December 2007

The successful development of a light weight slurry system for cementing long intervals at high temperatures in three dimensional multiple stacked gas zone wells, has been achieved in the Gulf of Thailand. The cementing system has been developed to successfully complete progressively more difficult wells, starting with conventional large bore wells and tubing plus packer completions, and later down-sizing into single monobore wells whereby the tubing is cemented in place. The problems associated with the down-sizing of the wells are further increased by more challenging well paths and higher temperature fields. Many problems and risks were overcome to complete this task successfully. These changes have posed new challenges in primary cementing.

Like the well size, the slurry system has also undergone a refinement and improvement process. The local industry has gone from dry blended slurry systems to all-liquid additive slurry systems saving considerable dollars, whilst realizing large gains in slurry flexibility, ease of mixing and improved logistics. Whilst developing and realizing these gains, the system has been refined and successfully applied to smaller, hotter and more difficult wells.

This paper presents the concerns associated with cementing these challenging wells where remedial cementing has been effectively eliminated. The processes related to this success, evaluation methods and field results will be discussed.
Comparing Exploitation and Transportation Technologies for Monetisation of Offshore Stranded Gas
Authors: Chang Seungyong
Published: December 2007

Natural gas is one of the important energy resources and the worldwide consumption is rapidly increasing. To satisfy such a demand of the natural gas, a number of gas fields are under development in hostile conditions such as deep seas and arctic areas. However, due to the status of current technologies and economic situations, many gas fields in offshore are stranded. The estimated stranded gas reserves are above 4,500 TCF in offshore areas. The proven technology options available to the offshore for the natural gas exploitation and transportation are extremely limited. Currently, the most popular methods of bringing the natural gas to market from distant locations are LNG (Liquefied Natural Gas) and PNG (Pipelined Natural Gas) technologies. However, these technologies require expensive capital cost for infrastructure constructions and huge proved gas reserves. Thus, in many situations, they are not available for the stranded gas exploitation and transportation. There exist alternative technological options to LNG and PNG technologies that can be considered for exploiting and transporting the stranded gas in offshore. They are CNG (Compressed Natural Gas), NGH (Natural Gas Hydrate), GTL (Gas to Liquid), and GTW (Gas to Wire). In this paper, the available technologies of CNG, NGH, GTL, and GTW have been reviewed and compared to LNG and PNG technologies to derive the most economical one in selected regions such as Mediterranean, Caribbean, Arabian Seas, and Sakhalin Island.
Experimental Investigation of Critical Flow Condensate Saturation
Authors: Guo Ping , Yang Jinhai , Li Shilun , Sun Liangtian , Jiang Tongwen
Published: December 2007

When gas condensate reservoirs are developed by pressure depletion, retrograde condensation occurs at pressure below the dew point of the condensate gas reservoir. The minimum saturation required for the flow of condensate in reservoir rocks is so-called critical flow condensate saturation (CFCS). We often want to know how much the CFCS is, about this, some study indicates the CFCS is 30-50%. Yet, field experience indicates the CFCS at much lower saturation of around 10%, particularly in the presence of connate water. Although this may be ignored in laboratory studies, it could significantly contribute to recovery at field scale.

An experimental equipment by ultrasonic has been established in order to directly determine the CFCS in core at high pressure fluid system. At first, we verify the way by applying different kinds of porous media (no media, filling media and synthetic media) and test the saturated vapor pressure of CO2 in them, then we use two real gas condensate and two synthetic cores (one: porosity 37.1%, permeability 1.44 μm2, and another: porosity 38.6%, permeability 1.73 μm2) to determine the CFCS, we demarcate the connection between condensate saturation and ultrasonic signal and get the CFCS which one is 15%, another is 18%.
A New Method for Computing Pseudoskin Factor for a Partially-Penetrating Well
Authors: Lee K. S.
Published: December 2007

An accurate knowledge of pseudoskin is important to quantify an additional pressure loss due to partial penetration or restricted entry. Though several procedures for computing the pseudoskin factor have been reported in the literature, they are either insufficiently accurate for geometrically-complicated reservoir systems or require the solution of a fully-transient diffusivity equation. This study aims to present a new method for estimating the pseudoskin factor of a partially-completed well. It has been designed to overcome a limited applicability of previous methods in geometrical or computational aspects. The method is derived from applying the equation for the pseudosteady-state flow of a slightly compressible fluid and accommodates one or more openings in a single or multiplayer reservoir where a crossflow occurs between reservoir layers. The solution of a pseudosteady-state equation describes the pressure response of a closed radial system during a boundary-dominated flow period. A pressure drawdown of any reservoir system, which can be easily evaluated from the solution, is compared against the analytical solution of a fully-penetrated system. The pseudoskin factor is, then, determined from the difference between the two sets of results.

Comparisons with previously published results are presented graphically. The reservoir types include various cases of homogeneous and multilayered systems with contrasting reservoir properties. It is shown that a highly accurate estimate of pseudoskin factor can be achieved regardless of the complexity of a reservoir system including the location of open intervals or number of layers. With minimum assumptions on the reservoir geometry, a greatly improved computational efficiency of pseudosteady-state approach permits the engineer to account easily for the effects of partial penetration on the productivity of a partially-penetrating well.
Methodology to Incorporate Geological Knowledge in Variogram Modeling
Authors: Bahar A. , Ates H. , Kelkar M. , Al-Deeb M.
Published: December 2007

Geological knowledge is an important ingredient in a successful reservoir characterization process. Geoscientists and engineers have used variogram extensively as the tool to quantify the spatial relationship of various attributes, e.g., facies/rock type, porosity, and permeability. Proper variogram modeling is a key factor to obtain a geologically-sound reservoir characterization model. This paper discusses the difficulty that is commonly encountered by many practitioners in modeling the variogram and proposes a way to incorporate geological knowledge as the soft information to improve variogram model.

Common difficulty in variogram modeling is the calculation of horizontal variogram. The averaging technique that uses combination of geological knowledge and analogy in geophysical literature about frequency data analysis is implemented to solve the difficulty in calculating horizontal variogram. This technique has produced results that are agreeable with geology of the reservoir.

The art of incorporating the geological knowledge in variogram modeling lies in the fact that geological knowledge is a qualitative measure whereas variogram is a quantitative measure. The methodology to combine these two measures presented in this paper is as follows. First, interpreting various geological aspects of the reservoir in detail. These include, but not limited to, the interpretations of geological environment, sequence stratigraphy, pore-space characteristics, iso-chores, iso-porosity and iso-permeability maps. From these interpretations, a summary table, that includes the major continuity direction, lateral extension and anisotropy index of each attribute, is prepared. Second, calculating experimental variogram using the Averaging Technique. Third, modeling the experimental variogram considering the information obtained from the first step.

The procedure presented above has been implemented as a routine procedure in several reservoir characterization studies for both carbonate and sandstone reservoirs in the Middle East and in the USA. For illustration purposes, comparison of the realization results, taken from carbonate field study, between the model with variogram derived purely from the hard data, i.e., well log data, and the variogram derived from both hard and soft data, i.e., geological knowledge, is presented. It is concluded that the incorporation of geological knowledge has improved the confidence level of the results and should always be part of any reservoir characterization study.
Erb West Field: The World's First Offshore Level 6 Multilateral Well
Authors: Samsudin Noren , Kassim Abdullah , Khalid M Zaidan , Rahman A. Aziz A. , Che Mad Abu Bakar , Liau Richard , Jabs Matthew , Lim Ben
Published: December 2007

The oil industry has lately seen the introduction of more complex, purpose built multilateral wells of the TAML (Technology Advancement Multilateral) levels 4 and 5 categories. The debris management issues, junction integrity and the risk involved in the well construction are still perceived as operational challenges to operators. In reviewing the risk profile, operators and service companies alike have sought to look into techniques outside the realm of conventional well construction methods. Expandable tubular technology is one such area. The manufacturing concept is to form a junction with a 9-5/8" trunk casing branching into two separate 7" liner legs. This junction is then pressed and formed in order for it to be able to pass through the drift ID of 13-3/8" casing. The junction is then reformed downhole using an innovative downhole swaging process.

This paper describes the process of deploying the TAML level 6 multilateral junction in the Erb West Field (offshore Malaysia) during the EWDP-A Revisit 4 Campaign (well EW-117S1). The discussion follows the full cycle of well construction for a level 6 multilateral junction. It encompasses the well planning phase, the deployment and the installation phase, the lateral drilling phase, and finally the completion of the level 6 multilateral well. The result is a multilateral well construction technique which eliminates the debris management, reduces well construction risk and provides a hydraulically sealed junction, integral with the trunk casing.
Production System Optimisation - Offshore West: The First Pass
Authors: Naizatulakmal Abdullah , Kassim Salawati Hj , Min Mook Wah , Ahmad Rosiah Hj
Published: December 2007

Squeezing the extra barrel of oil from a brown field asset requires a structured working methodology to maximise a field's total potential both from the subsurface and surface aspects of operations. Brunei Shell has introduced the concept with a Production System Optimisation (PSO) Team in 1997. This proved very successful and Brunei Shell has therefore taken another step towards realising the limit with the setting up of three dedicated PSO teams, one for each of the geographic operating areas. The paper will outline the ongoing efforts made by one of these three PSO teams, the "West" team, in identifying production opportunities in the offshore Ampa, Fairley and Gannet fields. The nature and scope of work that has been carried out so far includes simplification of process design, reducing deferments, realising the field's lock-up potential, removing process bottlenecks and optimising the operating envelope. This is often achieved by applying "out of the box" approaches to deliver innovative business solutions. This will be demonstrated with examples. The working methodology and key learning points outlined in the paper can easily be adopted by other oil and gas operating companies. From the PSO/1 implemented activities, an average of 320 m3/d/annum nett oil production has been delivered for the year 2000, generating revenue amounting to US$60300 per day (at US$30/barrel) and a saving of 70% on CAPEX.
Fluid Characterization of an Iranian Carbonate Oil Reservoir Using Different PVT Packages
Authors: Ghorbani D. , Kharrat R.
Published: December 2007

Precise and accurate characterization of a reservoir fluid is a very important factor in reservoir simulation studies. PVT experiments are usually expensive and performed in limited conditions. Therefore Computer EOS based PVT packages are used widely for the prediction and evaluation of fluid properties at reservoir, well and surface conditions over a wide range of temperature, pressure and composition1,2,3,4. In this work different PVT packages that are available in National Iranian Oil Company (NIOC) have been used to complete fluid analysis and experiment simulation of an Iranian oil reservoir and PVT model preparation for the reservoir simulators. This reservoir is a medium size, highly fractured carbonate reservoir located in southwest of Iran. The carbonate formation has dense matrix with improved permeability by presence of fracture network. This reservoir was initially highly undersaturated and after 5 years of oil production the oil pressure reached to the saturation pressure and gas injection was started into the reservoir5.

In this work different equation of states, different regression methods and correlations were analyzed for the prediction of fluid properties. Considering the results of this work in general good agreement was obtained for the experimental and calculated data for used packages. However, the method used for tuning the equation of states is critical in getting good agreement.
Hydraulic Fracture Stimulation of the BRF Clastic Formation, Ramba Field, South Sumatra Indonesia – a Case Study
Authors: Effendi Prijandaru , MacNeill George , Badri Mohammed
Published: December 2007

The Baturaja (BRF) Clastic Formation in the Ramba Field of South Sumatra, Indonesia must be hydraulically fracture-stimulated to produce the reservoir at an acceptable economic level. Early efforts at producing from this formation were disappointing. A combination of a detailed reservoir engineering study and developments in fracture stimulation technology has made this zone an economic success.

The detailed engineering study allowed for a better understanding of the permeability variations within the formation across the field which in turn helped in the selection of optimum placement of the wells and individually tailoring the fracture stimulation treatment designs to suit particular well and reservoir conditions.

Early fracture-stimulation treatment designs used oil-based and water-based titanate/zirconate-crosslinked fracture fluids systems with mixed results. The most recent fracture stimulation treatments have employed a combination of a low polymer loading water-based borate-crosslinked fluid, and a Surface Modification Agent (SMA) to the proppant. The SMA increases the fracture conductivity, creates a flexible, stable proppant pack, reduces fines migration and fines invasion of fracture pack, assists in proppant flow back control; and reduces fracture cleanup time.

Sixteen wells were completed in the Clastic formation in late 1999 and early 2000. This paper discuss the design details and explains the changes made to the hydraulic fracture stimulation treatments to make this formation an economic success.
A Knowledge-Based System for Optimal Economic Design of Improved Recovery Processes
Authors: Gharbi R. B. C.
Published: December 2007

The main challenge of Enhanced Oil Recovery (EOR) processes at the prevailing low oil prices is to reduce the cost. An optimization methodology, combined with an economic model, is implemented into an expert system for optimizing the net present value of full field development with an EOR process. The approach is automated and combines an economic package and existing numerical reservoir simulators to optimize the design of a selected EOR process using sensitivity analysis. The EOR expert system includes three stages of consultations: (1) select an appropriate EOR process on the basis of the reservoir characteristics, (2) prepare appropriate input data sets to design the selected EOR process using existing numerical simulators, and (3) apply the discounted-cash-flow methods to the optimization of the selected EOR process to find out under what conditions at current oil prices this EOR process might be profitable. The project profitability measures were used as the decision-making variables in an iterative approach to optimize the design of the EOR process. The economic analysis is based on the estimated recovery, residual oil in-place, oil price, and operating costs. Two case studies are presented for two reservoirs that have already been produced to their economic limits and are potential candidates for surfactant/polymer flooding, and carbon-dioxide flooding, respectively, or otherwise subject to abandonment. The effect of several design parameters on the project profitability of these EOR processes was investigated.
A Novel Technique to Treat Asphaltene Deposition in Carbonate Rocks
Authors: Zekri Abdulrazag Y. , Almehaideb Reyadh A.
Published: December 2007

In this project, steam was tested to stimulate damaged limestone cores. Several dynamic experiments were conducted to determine the effect of asphaltene on the permeability of limestone cores. Plugging effects due to asphaltene deposition were evaluated through comparison with reference permeability measured prior to and after oil flow. Damaged cores were then subjected to steam soak process. The permeability of the cores was measured after each treatment. Core impairment resulting from in-situ asphaltene deposition, was found to cause a 56 to 89% loss of initial oil permeability depending on rock permeability and injection rate. Core stimulation resulting from steam soak treatment, was found to cause 24 to 230% improvement on the damaged core permeability depending on rock permeability. On average, 95% improvement in damged core permeability was obtained.
Experimental Investigation of the Feasibility of Steam/Chemical Steam Flooding Processes through Horizontal Wells
Authors: El-Abbas Abbas A. , Shedid Shedid A.
Published: December 2007

Laboratory studies and field applications have strongly established steam flooding as a valuable and remarkable recovery technique for both vertical and horizontal wells. This experimental study presents an investigation of the potential of enhancing tertiary oil recovery of heavy crude oil using steam, caustic steam, surfactant steam, and caustic-surfactant steam flooding through horizontal wells. The oil recovery of each process is measured and a comparison is carried out. The experiments were conducted using a box-shaped sandpack equipped with a centered horizontal well. The followed experimental procedure used the configuration of a horizontal steam injector with a vertical producer. The results of the dynamic experiments indicated that steam flooding through a horizontal well substantially improved oil recovery. Addition of caustic (sodium hydroxide) or surfactant (X-Triton-100) to steam drive recovered additional oil of 2.7 % IOIP or 5.6 % OOIP, respectively, than conventional steam flooding for water flooded reservoirs through horizontal well. In addition, the use of mixed solution of caustic and surfactant into steam current potentially enhanced oil recovery by almost 7.5 % IOIP than conventional steam flooding through horizontal wells for water flooded reservoirs. The above results indicate that steam and/or suggested chemical steam techniques are efficient methods for recovering heavy oil from water-flooded reservoirs. Key Words: Thermal methods, Chemical methods, Horizontal wells, and Fluid flow.
Development of Non Petroleum Base Chemicals for Improving Oil Recovery in Indonesia
Authors: Suryo Purwono , Murachman Bardi
Published: December 2007

The advantages of oil as primary energy source are still unsurpassed by any other source. After primary and secondary recovery, approximately 50 % to 70 % original oil in-place were left in reservoirs. The oil left is unrecoverable by conventional means. The enhanced oil recovery or tertiary oil recovery indeed is a very promising effort in the future. The goal of this research is to develop chemicals produced from local materials which can be used to optimize recovery and minimize residual oil in the reservoir by: lowering the oil / water interfacial tension and improving mobility ratio. A laboratory experiment had been carried out to simulate the process. The porous media used in the oil displacement process was prepared from stainless steel cylinder and contain fine crushed core. It is proposed to be an artificial reservoir with dimension about 3.75 cm ID x 10.8 cm L. The procedure of operation is as follows: initially the reservoir model was filled with brine until 100 % saturation. Then oil was injected into the medium to represent oil migration until water saturation become minimum (Swc), which is about 30 %. After this, the reservoir was flooded by the same brine until Sor was reached, which is about 10 %. The oil remaining in the reservoir after this water flood was then subjected to various injection of different chemicals for further oil recoveries. The experimental results show that some chemicals developed in the laboratory can be used as EOR chemicals. The oil displacement experiments show that as much as 20 % to 80 % of remaining oil can be recovered by flooding it with the chemicals. The results also show that the oil recovery depends on type of chemicals, chemical concentration, pressure and temperature, type of crude oil and the brine concentration.
Characterization of the Plus Fraction and Prediction of the Dewpoint Pressure for Gas Condensate Reservoirs
Authors: Elsharkawy Adel M.
Published: December 2007

This paper presents a new empirical model to estimate the dewpoint pressures for gas condensate reservoirs as a function of routinely measured gas analysis and reservoir temperature. The proposed model was developed using experimentally measured and collected data of 340 gas condensate samples covering wide rage of gas properties and reservoir temperature. The new model has an average relative deviation of 0.44 % and average absolute of 7.68% or 346 psia. The accuracy of the model has been compared to SRK-EOS, PR-EOS, and other correlations. The model proved to be superior for most of the gas condensate samples used in this study. Gas condensate samples from this study as well as from literature have been used to check the validity of the proposed model against EOS simulation. These examples have shown that the model successfully captures the physical trend and that the model is reliable. This model is useful to provide an estimate of the dewpoint pressure when experimentally measured ones is not available.

The current study also shows that predicting the dewpoint pressure for gas condensates depends on the EOS(s), the number of pseudo-components, and the characterization of the plus fraction. For most of the gas condensate used in this study, a ten to twelve pseudo-component of the heptane plus fraction resulted in minimum error in calculation of dewpoint pressures using PR-EOS with Pedersen characterization of the plus fraction.
Neural-Network Approach To Predict Well Performance Using Available Field Data
Authors: He Zhong , Yang Linyu , Yen John , Wu Ching
Published: December 2007

Accurate prediction of future well performance is of great importance for petroleum reservoir management. This paper presents a practical neural network approach to predict existing and infill oil well performance using available filed data, such as well production history and well configuration information. It serves as a practical, cost-effective and robust tool for oilfield production and management. Well production, well spacing and the time-dependent information are used to train the neural network. The time-dependent information of wells are incorporated in a manner of time series for establishment of neural network. After the neural network is established, it is used to predict future performance of existing and infill wells. No reservoir data is currently used in the establishment of neural network, therefore it can predict well production performance in absence of reservoir data. Primary production of two data sets (each has 9 wells) in North Robertson Unit located in west Texas was tested using this approach. The results demonstrate that this approach is powerful in rapid projection of existing wells’ future performance, as well as the performance prediction of infill drilling wells.
Advanced Well Simulation in a Multilayered Reservoir
Authors: Verga F. M. , Griffa G. L. , Aldegheri A.
Published: December 2007

In the past years technological advances in drilling and completion have provided the possibility of improving the reservoir productivity by resorting to new options such as multilateral wells and intelligent completions or a combination of both. However, some serious difficulties arise to simulate the performance of advanced wells as standard well models neglect friction effects along deviated drains and do not allow selective fluid flow control when bottom hole flow control devices are used.

Some new simulation options have been recently developed that, reportedly, provide a thorough description of the local flowing conditions along the well and account for pressure losses along the wellbore and across any flow control device. The new simulation options were applied to simulate the performance of a dual opposed, stacked lateral well completed with bottom hole flow control devices draining an oil reservoir comprising two hydraulically separated pools. During the first years of production the two drains were initially left open hole. When water break through occurred and water production started to progressively increase, the possibility of adopting an intelligent completion to control fluid entry from each drain appeared very attractive to optimise oil production. Therefore, a 3D numerical model of the reservoir was set up. Once the calibration of the model was attained, the use of intelligent completions was simulated in an attempt to evaluate the reservoir performance when flow control was applied to each drain, and to determine the optimal well configuration to maximise productivity. Productivity forecast showed that intelligent systems allow both enhancement of oil production and dramatic reduction of water production compared to the case where conventional completions are adopted.
Modeling and Simulation of the Wafer Non-Darcy Flow Experiments
Authors: Li Dacun , Svec Robert K. , Engler Tom W. , Grigg Reid B.
Published: December 2007

Darcy's law governs most flow patterns in petroleum recovery processes. However, when fluid flow velocity is very high, for example, near the wellbore, Darcy's law may be inadequate to simulate the fluid flow.

The non-Darcy effect has been incorporated into the Department of Energy (DOE) reservoir simulator MASTER (Miscible Applied Simulation Techniques for Energy Recovery). Based on the simulator BOAST (Black-Oil Applied Simulation Tool), MASTER was developed by DOE mainly to solve gas injection problems. However, only Darcy's flow was considered in these simulators. In this study, Forchheimer's non-Darcy flow equation has been incorporated into the simulator code and an iterative method has been used to solve for pressures.

The modeling of non-Darcy flow proved successful and enabled the simulator to match high-velocity gas flow more accurately. Based on a number of non-Darcy flow coefficient equations found in the literature, a general correlation was proposed. The appropriate constants in the proposed correlation were found by running simulations with the modified simulator for the non-Darcy flow experiments.

The model has been verified using laboratory high flow data obtained using single-phase nitrogen gas. The data comprised a wide range of flow rates collected using a heterogeneous Berea sandstone wafer. The gas flowed into and out of a hockey puck-shaped wafer via 0.125-in. diameter ports. Thus the flow rate varied within the wafer, simulating near-wellbore flow conditions. It was found that, the differential pressures from simulations were in good agreements with their counterparts from experiments.
Mapping of Permeability Structure in a Naturally Fractured Reservoir Using Field Performance Data
Authors: Anguiano Juan A. , Ershaghi Iraj , Christensen Karen I.
Published: December 2007

This paper presents the results of a detailed study examining the permeability characteristics of a naturally fractured reservoir using the performance data from individual wells. The study relates to naturally fractured reservoirs where the wells that intersect highly fractured and brecciated intervals are the most prolific producers. Substantial historical production history data on individual wells are examined using a type curve approach. The early production decline, from fracture-controlled period, is used to estimate equivalent permeability-thickness product for individual wells. The matching process is similar to the method suggested by Fetkovich1 for homogeneous reservoirs. Deviation from this model, attributed to a support system, is compared with two plausible systems. Because of the rapid onset of the deviation from the fracture controlled decline, high values of interporosity parameter are noted unmatched by observations from matrix petrophysical properties. The two systems compared are the dual-fracture model published by Al-Ghamdi and Ershaghi2, which is selected for its representation of network of microfractures as the main support system, and the dual porosity/permeability models which are the most commonly used models in commercial simulators to represent naturally fractured reservoirs.
An Investigation of Counter-Current Imbibition Processes in Diatomite
Authors: Zhou D. , Jia L. , Kamath J. , Kovscek A. R.
Published: December 2007

Oil recovery from low permeability reservoirs is strategically important because of the large resources locked in such formations. Imbibition is fundamental to oil recovery from such reservoirs under most secondary and improved recovery processes of practical interest. It is also characteristic of porous medium wettability. The rate and the extent of imbibition depend critically on the viscosity of the wetting and nonwetting phases. In this study, we present our recent work on imaging imbibition in low permeability porous media (diatomite) with X-ray computed tomography. The viscosity ratio between nonwetting and wetting fluids is varied over several orders of magnitude yielding different levels of imbibition performance. We also perform a mathematical analysis of counter-current imbibition processes and develop a modified scaling group incorporating the mobility ratio. This modified group is physically based and appears to improve scaling accuracy of countercurrent imbibition significantly.
Relief for worn-out API Ring Wellheads
Authors: Jones Jeff
Published: December 2007

Texaco has been concerned for years with the problems of wellhead emissions and has spent much time and money on prevention and control. One weak point in the typical wellhead system is the API ring wellhead flange seal. Improper installation procedure is the main cause of seal failure. For those few instances of defective flanges, Texaco developed an elastomer backup seal that prevents expensive flange replacement.
Dynamic Flow Performance Modeling of a Gas-Lift Valve
Authors: Faustinelli J. G. , Doty D. R.
Published: December 2007

A new unified model that predicts the flow performance of nitrogen charged injection pressure operated gas-lift valves has been developed and is able to predict the volumetric flow rate more accurately than previous models. The new model exhibits orifice, throttling and transition flows which encompass all of the flow regimes encountered in a gas-lift valve. The model is based upon fundamental physical principles and has the advantage of describing the internal flow mechanics occurring at the ball-seat and port locations.

The model predicts an isentropic process from the upstream condition to the minimum flow area. The model also predicts a pressure recovery associated with the sudden gas expansion occurring beyond the minimum area of flow. This recovery was verified by experimental data, and it has been included in the new model. Previous models did not incorporate the pressure recovery effect, and in order to match the experimental data, it was necessary to empirically modify the compressible flow theory used to develop these models.

The new model is simpler (i.e. requiring fewer empirical coefficients), more reliable, more accurate and more theoretically consistent than previous models. The new model allows a feasible explanation of the fundamental physical behavior of the different flow regimes within a gas lift valve. Experimental data, obtained from a dynamic test facility, show an excellent agreement between the data and the predictions generated using the new model.
Use of Coiled-Tubing on Production Wells Located in the San Jorge Basin
Authors: Zurita D. N. , Abella F. J. , Luongo S. , Maino J. C. , Montenegro E. M. , Panza L. A. , Lopez R. E. , Sequra H. R. , Romero V. M. , Cavieres G. E. Gomez , Homes A. H. , Romero E. O.
Published: December 2007

In the continuous search of the optimization of investmensts and the reduction of operative costs, Repsol-YPF decided to research the possibility of the use of Coiled Tubing to produce traditional diameter wells at the Golfo San Jorge Basin. This represents a further step after an experience undertaken in reduced diameters started in 19971.

Through this new experience it was proven that it is posible to produce wells with diameters higher than 3.5 in. Using coiled tubing in mechanical pumping, generating at the same time new possiblilities for coiled tubing with other artificial lift systems.
Problems in Gas Hydrates: Practical Guidelines for Field Remediation
Authors: PAEZ J.E. , Blok R.
Published: December 2007

Natural gas hydrate formation is a costly and challenging problem for the oil and gas industry. In recent years, two new families of chemical additives have been commercially developed to prevent hydrate plugging problems in production lines. This approach is commonly known as low-dose inhibition, and the two families are kinetic inhibitors and anti-agglomerants. Evolution of these new products is proceeding at a rapid pace, in order to meet goals of covering a greater range of operating conditions and finding an economically and environmentally attractive alternative to thermodynamic inhibition.

Successful deployment of low-dose inhibitors depends on an appropriate selection of inhibitors and a complete understanding of the system. Based on a synthesis of available literature on application of low-dose inhibitors to hydrocarbon processing equipment and handling facilities, this paper describes a methodology for designing a deployment strategy. This guide provides a systematic approach to aid production engineers in deploying low-dose inhibitors in existing facilities and new developments. An easy-to-follow flow chart is given.

The information provided in this article was compiled from published data, and experience provided by several companies in the oil and gas industry.

Introduction

Natural gas hydrate formation is a costly and challenging problem for the oil and gas industry and tends to be most critical for offshore facilities. Since the time when hydrates were first identified1, the oil and gas industry has injected a constant flow of resources into the search for an economic and environment friendly solution to the problem of hydrate prevention.

Thermodynamic inhibition has been the conventional approach to natural gas hydrate inhibition. System composition or operating conditions are altered so that over the range of operating temperatures and pressures, the hydrocarbon system falls outside the pressure-temperature region in which hydrate formation can occur. (See Figure 1)2.

Keeping operating pressures and temperatures out of the hydrate formation region can be achieved by making system adjustments such as applying heat, using insulated pipelines, or adding chemical compounds (thermodynamic inhibitors) that change the behaviour of the new mixture.
A systematic Approach to Sampling During Well Testing
Authors: Dybdahl Bjørn , Hjermstad Hans Petter
Published: December 2007

The industry is focusing on cost reductions by saving on expensive rig time and on reducing the impact on the environment during well testing. Decisions regarding field development are increasingly taken based on the results of samples and data obtained by wireline formation tester/samplers (WFT/S) and not on data obtained by flow to surface during a drill stem test. The use of oil-based mud to increase the drilling rate is also becoming more common. These measures reduce the likelihood of obtaining quality fluid samples and increase the uncertainty in field development projects related to fluid data. A systematic approach to fluid sampling is presented which discusses the different aspects related to the quality of fluid data obtained depending on the sampling method, type of reservoir fluid system and formation properties. Recommendations for the decision making process are presented.
First Horizontal Well Opens New Gas Opportunities in the Sierra Chata Field, Neuquén Basin, Argentina
Authors: Sanz C. A. , Nilson G. J. , Acree J. F. , del Pino M.
Published: December 2007

The first horizontal re-entry gas well was successfully drilled and put on line in the Sierra Chata field in the Neuquén basin in Argentina. This article compares the model forecast with the results obtained. The objectives were: (1) to add gas reserves and (2) to incorporate horizontal technology that will allow access thin or low permeability sands, in remote areas that would be economically marginal with vertical wells.

Recent interpretation of 3-D seismic and geologic data indicated that the "D" Sands were better developed to the northwest of the vertical well SCh-17. In order to access gas reserves postulated to exist there, it was planned to drill a horizontal re-entry well utilizing the existing vertical well, SCh-17 as a re-entry conduit. From the well SCh-17 a re-entry was made at 244 m from the deviation point (KOP) in 1600 m MD, drilling slightly up-dip to 2975 m MD, using with a downhole motor and a MWD logging system.

Shale-silt lithologies within the sand members affect the vertical transmissibility (TZ) between the "D" Sand members. Sensitivity runs were made using a reservoir simulator built to test the effect of such variables on the horizontal well productivity. For the most probable case, an initial flowrate of 17.7 MMscfd (502 Mm3/d) was predicted. A final cumulative production of 7.3 BSCF (206.7 MMm3) of gas was predicted by the numerical simulation model.

Six months of production history confirmed the forecast and assumptions made in the well proposal and also encourage new horizontal prospects. This year, two additional horizontal wells have been proposed to be drilled in the Sierra Chata field applying some of the concepts proven by the subject well. At least one of which will include an additional deviation of the horizontal wellbore to intersect multiple target zones.