bluuebunny/crossref_metadata_2025 huggingface dataset:
Five Years of Ongoing Conformance Work in the Central Mallet Unit CO2 Flood in West Texas Yields Improved Economics for Operator
Authors: Honnert M. , Creel P. , Tate R. , Everett D.
Published: December 2007

This paper reports the results of a 5-year effort to improve and enhance field-wide conformance. The developments on data analysis, reservoir and production engineering, and solutions in these mature units have provided the opportunity to make major impacts on recovery and production rates, operation enhancements, and cost reductions. The term "conformance" used in the context of this paper is given to mean "to influence the fluid flow that occurs in a petroleum reservoir." If we can gain influence over the action of formation fluids and introduced fluids and gases, we may have the power to bring more hydrocarbons to the surface and leave more undesirable fluids in the reservoir.

In 1999, a team was formed to solve field-wide conformance problems in a San Andres (dolomite) unit of the Slaughter Field, Hockley Co., Texas. The team's visualized goal was to improve unit economics by increasing oil production and decreasing production costs, using a better understanding of fluid movement through the project reservoir. The team was made up of both operating and service company personnel to accomplish the required data analysis, engineering, and solution designs that were required.

The original strategy was to form a full-functioning reservoir conformance team to identify, quantify, and fully describe field conformance problems. Focusing on the total reservoir, they developed a framework of data required to design a successful conformance solution. This data framework includes information of the reservoir, completion design, drilling and workover history, production and well-test history, logs and diagnostic analysis, and placement options. The framework also served as a tool to identify what data was lacking. An optimum conformance solution design was the team's vision.

This follow-up report based on the ongoing work over the past 5 years demonstrates the functionality of the methods and techniques used with a performance evaluation for defining successes thorough a review of the operator's economic drivers for sweep improvement, reduction of CO2, and water cycling-breakthroughs.
Why the LWD and Wireline Gamma Ray Measurements May Read Different Values in the Same Well
Authors: Mendoza A. , Ellis D. V. , Rasmus J. C.
Published: December 2007

Many concerns have been expressed regarding discrepancies between LWD (Logging-While-Drilling) and WL (Wireline) GR (natural gamma ray) responses in various wells. It has been suggested that these differences may arise from the variations in tool design that would be sensitive to the relative mixture concentration differences of Thorium, Uranium and Potassium between the University of Houston calibration test pits and the actual formations logged. Other causes have been attributed to errors in the characterization process and to the amount and accuracy of the borehole corrections algorithms applied to the measured values.

To answer these questions, we used the Monte Carlo code MCNP in combination with an in-house code, GAMRES, to simulate the response of the various gamma-ray detectors in a variety of LWD and Wireline tools. Each tool is sensitive to the Thorium, Uranium and Potassium concentrations depending on their particular geometric parameters such as NaI crystal size and thickness of the collar material surrounding the detector. To determine this sensitivity, an overall sensitivity coefficient is calculated for each tool at the time of calibration in a pit of known concentrations of Thorium, Uranium and Potassium. Under different borehole conditions (mud weight, barite mud, borehole size, etc), the tools would respond differently depending on their particular sensitivity. This modeling allows us to assess the difference in API units between the LWD and Wireline gamma-ray based on the tools geometric configuration, borehole size, Thorium, Uranium and Potassium concentrations, and mud weights both before and after applying the published borehole correction algorithms.

Results from this study indicate that significant response differences may arise, not from tool design differences, but from different borehole and/or mud conditions if appropriate corrections are not applied.
5K Dual Splitter Wellhead System: 1st Middle East Deployment on an Offshore Oilfield, Combining Simultaneous Production and Drilling on Adjacent Wells Within the Same Conductor
Authors: Santos A. , Floch A.
Published: December 2007

Splitter type Wellheads permit the drilling of two or more wells from within the same conductor pipe / caisson, resulting in significant savings for offshore drilling projects by potentially reducing both the size and quantity of wellhead platforms required for the field development.

In addition, on mature fields such as Total ABK, where no new slots exist and the installation of additional Wellhead platforms would not be cost effective, the addition of a cantilever deck to an existing platform and the use of a Splitter Wellhead system, presented a viable solution for an additional eight well slots, from four conductors.

From February to June 2005, two (four wells) Cameron nominal 13-5/8" 5K dual Conductor Sharing (CSW) systems were successfully deployed offshore by Total Abu Al Bukhoosh, using standard ABK well architecture of 13-3/8" × 9-5/8" casing strings, 7" liner and a 4-1/2'" gas lift completion with 4-1/8" 5000 psi Xmas Tree, from within a 36" conductor. A further two systems are being deployed since November 2005, to complete the current project.

All four wells of the Phase I project were installed, drilled and completed without any significant problems, ahead of the planned time schedule and under budget. The drilling and completion of these wells were performed under SIMOPS. Wells were put on production as soon as they were completed and were being produced while drilling and completing the other well on same conductor pipe. This resulted in savings equivalent to over a month of cumulative production per well.
Interpretation of Water Injection/Falloff Test—Comparison Between Numerical and Levitan's Analytical Model
Authors: Azarkish Abbas , Khaghani Elham , Rezaeidoust Alireza
Published: December 2007

Water injection/fall off tests are normally associated with water flood project. Recently, interested in this type of well tests has developed in the area of reservoir appraisal. In the vast majority of situations associated with exploration activities, there is no infrastructure and equipment in place to collect and export the hydrocarbon produced during well test. The common practice used in the industry is to burn the produced fluid.

The demands to reduce emission during well tests put enormous pressure to avoid these tests together. This brings large uncertainties to the reservior appraisal and increases the investment risk if a decision is made to sanction a project and to develop the field. Replacing a production/build up test sequence by an injection/fall off test sequence solves the problem of emission.

Levitan[1] stated that three main problems due to using water injection / fall off test might happen which are listed below:

The first problem is that the character of the system changes and Instead of single-phase flow we face now with two-phase water-oil flow by their own relative permeabilities. The second problem is injection of cold water includes temperature changes in the formation and brings additional complication to pressure behaviour through temperature effects on the oil and water viscosities and the third one is injection of water may result in the formation fracturing and in coupling of rock mechanics and fluid flow problems. It is therefore, important for successful test interpretation to avoid fracturing and to inject water at below the formation fracturing pressure.

This paper is divided into two parts. In the first part we are going to compare Numerical and Levitan's Analytical model for different injection and fall off periods using numerical part of Saphir well test software.

In the second part as far as we have validated Saphir Numerical model compared with W-O Levitan Analytical model, now this model is used to generate pressure responses in order to investigate the influence of reservoir parameters. Methods of interpretation will be used and some specific advantages of the numerical model will be shown.
A Review of Over 100 Polymer Gel Injection Well Conformance Treatments in Argentina and Venezuela: Design, Field Implementation, and Evaluation
Authors: Norman C. , Turner B. , Romero J. L. , Centeno G. , Muruaga E.
Published: December 2007

During the last 15 years, polymer gels have become an accepted technology for improving volumetric sweep efficiency in heterogeneous waterfloods. Water injected subsequent to the gel treatment ideally enters previously unswept zones with significant mobile oil saturation.

Results from several field projects in four hydrocarbon basins in Argentina and Venezuela are described based on the application of two available polymer gel technologies: Marcit℠ and Unogel. The types of reservoirs and reservoir conditions where polymer gels have been successful, and unsuccessful, are illustrated. Fundamental reservoir rock and fluid characteristics, reservoir temperatures, polymer gel designs, and project evaluation are presented for each of the field projects. A high temperature (275°F) reservoir is included.

In multi-layered reservoirs where crossflow is believed to be limited, one strategy is to inject a small gel volume in order to improve the vertical profile in the near wellbore region. If crossflow is believed to exist between layers or within a layer, significant gel volumes are recommended for deeper placement in the offending zones so that water cannot easily bypass the gel treatment.

Gel formulation is a fundamental issue. Traditionally, minimum polymer concentrations of at least 3000 ppm have been recommended for injection well gel treatments. Lower polymer concentrations were believed to be ineffective. A large scale and ongoing field project is presented in which low concentration polymer gels have been successful. In the same field project, the results of multiple gel treatments in the same injection well are discussed.
Lightweight Slurries—A Success Story of Application in Low-Fracture-Gradient and Depleted Fields for Improved Cementation
Authors: Dasgupta Debasish , Banerjee Satinath , Garg Satya Prakash , Jain V. K.
Published: December 2007

Till the recent times, covering the entire hydrocarbon bearing zones and simultaneously attaining quality cement bondage was a practical operational problem in the low fracture gradient and depleted fields of ONGC as the conventional lightweight slurries required for such conditions have low compressive strength, high porosity and high permeability which limit their application. Finding a feasible solution by developing lightweight cement slurry having adequate compressive strength was being investigated at the Institute of Drilling Technology (IDT) in ONGC for the past couple of years. Extensive studies performed culminated in the development of lightweight cement slurry systems for application in low fracture gradient and depleted formations to eliminate the losses during cementing and subsequent zonal isolation problem.

Formulated slurries inspite of low density have inherent properties of high compressive strength, low fluid loss, improved rheology, high stability, exceedingly low permeability and gas tight property. Field implementation results confirmed raising of long cement column without any losses and effectively encountering the perennial problem of cementing casings in low fracture gradient wells of Mumbai High in western offshore and CBM fields in India. A comparison of cementation with conventional and lightweight slurry system in the same field revealed better results with the latter.

This paper established the significance of application of these innovative lightweight slurry systems in terms of better well completion, reduced cost, improved productivity and less safety/environmental hazards in cementing across highly depleted zones and weaker formations. The details of the development, case studies of successful field implementation alongwith conclusions and recommendations derived from this endeavour are presented in this paper.
A Systematic Approach to Improved Success With Hydraulic Fracturing Applications
Authors: Jennings A. R. , Westerman C. W. , Tadlock D. W. , Westerman R. , Anderson M.
Published: December 2007

Methods to obtain better results with hydraulic fracturing in low permeability sandstone formations are constantly being developed. Fracturing techniques employed are often cyclic in nature, catalyzed to a large extent by gas and oil prices and corresponding costs of the stimulation treatments. "Optimization" of the fracturing approach may often seem arbitrary and raise the question: "Optimum …. Compared to what?"

Technology for improvements in hydraulic fracturing results is advancing at a rapid pace from the 3-D Seismic measurements used to define pay structure all the way to improved real-time mapping of fracture propagation. Extensive data gathering projects, however, are frequently big budget items and require dedication of manpower and resources. Therefore, such data measurement often tends to be reserved for projects of a regional scope.

This paper discusses several case studies of fractured wells in the Cotton Valley formation in East Texas and describes systematic changes in fracturing techniques used to improve treatment success. Comparisons of production data (short term and long term) are used to illustrate the degree of improvement. Readily available information (open hole logs, RA Tracer Logs, and PLT logs) was used systematically in this study.
Pitfalls in Performance-Data Tracking of Sucker-Rod Pumped Wells
Authors: Mahoney M. W.
Published: December 2007

Mean time between failure (MTBF) has been the standard for tracking field performance of sucker rod pumped wells but it can lead to improper conclusions and applications. A new method using cycle time and loading can greatly improve the understanding of the true performance of sucker rod pumped systems. Using proper data tracking of system performance and wear based on cycles and magnitude can greatly increase the understanding of a well system and be a proper guide to optimization.
Monitoring Multilayered Reservoir Pressures and Gas/Oil Ratio Changes Over Time Using Permanently Installed Distributed Temperature Measurements
Authors: Brown G. A.
Published: December 2007

Early identification of differential depletion in stacked reservoir sands, before water or gas breaks through, is the key to optimal reservoir drainage. However, hitherto it has not been possible to monitor reservoir pressure changes in individual layers after a well has been put on production without installing an intelligent completion or performing a multirate inflow performance relationship (IPR) test.

This paper describes a technique allowing individual layer pressures, or gas/oil ratios (GOR), to be monitored continuously during production. The technique employs the use of a rigorous near-well nodal reservoir pressure and thermal model to analyze permanently installed distributed temperature measurements. By modeling a range of typical flowing scenarios we demonstrate that distributed temperature measurements respond to changes in production caused by depletion in individual reservoir layers. We also show that in addition to flow rate determination, layer pressure changes smaller than 10 psi can be detected by changes in the measured temperature profile, as long as there is no breakthrough of gas or water. The model is also used to define the limits of the technique's operating envelope.

Increases in the flowing layer GOR will decrease the layers' fluid viscosity, resulting in a change in flow rate together with a decrease in flowing fluid temperature due to the Joule-Thomson effect. Consequently, layers where the GOR increases, identifying early gas breakthrough or fingering, can also be detected using distributed temperature monitoring.

The theoretical models are supported by real well examples, where the calculation of different layer pressures caused by depletion is confirmed by shutting in the well and observing the resulting crossflow with permanently installed distributed temperature monitoring. These models, along with continuously monitored temperature profiles, can be used to refine reservoir models and thus improve overall field recovery.
Uniform InFlow Completion System Extends Economic Field Life: A Field Case Study and Technology Overview
Authors: Lorenz Michael , Ratterman Gene , Augustine Jody
Published: December 2007

Horizontal wells on a global basis continue to serve as a primary well type for improving recovery efficiency, increasing reservoir drainage area, delaying water and gas coning and increasing production rate. However, in longer, highly deviated and horizontal wells, non-uniform flow profiles can result in premature water or gas breakthrough, screen plugging and erosion, which can shorten well life and decrease well profitability.

This paper describes historical and new applications of a proven production technology system that optimizes production, delays water and gas coning, minimizes annular flow to prevent erosion and ensures uniform inflow along the lateral at the cost of a minute pressure drop in high-rate horizontal wells. Case histories will be presented from the Norwegian Sector of the North Sea and offshore Saudi Arabia, where this production technology, combined with sand-control technology, has resulted in significant savings for the operator and improved production in horizontal offshore oil wells.
Application of NMR T2 Relaxation to Drainage Capillary Pressure in Vuggy Carbonate Reservoirs
Authors: Ouzzane J. , Okuyiga M. , Gomaa N. , Ramamoorthy R. , Rose D. , Boyd A. , Allen D. F.
Published: December 2007

Capillary pressure curves are a fundamental input to reservoir simulators both from the standpoint of initializing fluid saturations and from the perspective of predicting dynamic reservoir behavior. Traditionally, this input has been obtained from special core analysis (SCAL) from a limited amount of cores due to time and cost. Rock typing is often used to help map the available capillary pressure data to the reservoir layers.

Borehole nuclear magnetic resonance (NMR) has been demonstrated to provide pore size distribution information and methods exist in the literature to derive primary drainage capillary pressure data from the NMR log. In carbonates, however, it has been pointed out that variations exist in the relationship between pore body size and pore throat size. NMR is believed to reflect the former, while the latter controls capillary pressure. Hence, the applicability of NMR derived capillary pressure curves in carbonates has been questioned.

In a well in a complex carbonate reservoir, extensive log and core data has been acquired. We explore the correlation between NMR and mercury injection porosimetry through laboratory experiments on core samples from a variety of carbonate rock types. We further investigate the feasibility of determining primary drainage capillary pressure information from borehole NMR data and comment on the effect of tar or heavy hydrocarbon on the validity of the technique. We also explore methods to improve the accuracy of the results.

Our study shows the following: Under favorable conditions, it is possible to derive primary drainage capillary pressure curves from borehole NMR data in carbonate reservoirsCaution should be exercised in zones containing tar or heavy oilLaboratory studies on core can be used to enhance the accuracy of the results from borehole NMR dataResults from borehole NMR can be more representative of actual reservoir properties in vuggy carbonates than those obtained from SCAL measurements on core plugs of limited dimensions

We discuss the impact of the results on input to reservoir simulation and management.
Real-Time Image Data for Successful Horizontal Drilling in Carbonate Reservoirs Onshore Abu Dhabi, UAE
Authors: Ribeiro Maria Teresa , Al Neaimi Mohamed , Hendrawan Irfan , Karrani Sultan , Saad Mohamed Ben , Ayoub Mohammed R. , Zubair Kamal , Al Marzouqui Khalid , Khoori Suaad
Published: December 2007

The objective of this paper is to present the use of real-time image interpretation during an intensive drilling campaign of horizontal wells in two major carbonate fields onshore Abu Dhabi.

Seismic faults are identified using sophisticated methods for interpretation that revealed major faults as well as smaller ones. These are then calibrated using image logs while drilling the horizontal wells targeting the field development.

Achieving the objective of drilling horizontal wells depends on an accurate well placement within the reservoir which is related with the presence of structural features like formation dips and presence of faults along the hole trajectory. Careful pre-job planning using offset well data and seismic maps and x-sections helps on reducing the uncertainty. However, the unpredictability of structural and stratigraphic reservoir features between planned and offset wells information is always present. Even the formation dips computed from seismic and offset wells are prone to some degree of error.

The advances in real-time data transmission and LWD technology, namely resistivity and density image tools can be used for accurate modelling of the formation dips and structural anomalies and remedial actions taken immediately.

This paper describes the use of real-time image data interpretation and the great value in making geosteering decisions while drilling into reservoirs with structural complex/ unknown geology or in areas with sparse geological/ structural information.

Using image data, trajectories can be adjusted during drilling yielding optional well placement, but also actions for future wells, leading to a better success in the drilling campaign of long horizontal wells with a short tolerance radius.

An integrated multidisciplinary workflow is presented from well planning, using all available data including previous well information and the continuous update of the reservoir understanding, to immediate decisions while drilling. Several examples illustrate the different phases leading to the well conclusion and the use of such valuable information in better reservoir knowledge.

Finally, a comparison (LWD and WL) and value of information is also presented to highlight the advantages/ drawbacks of different tools on a case dependent selection.
Successful Drilling of a High Step-Out Ratio Well With Water-Based Mud in Morecambe Bay
Authors: Hodder M. , Ross N. , Gibb S. , Redgrave S.
Published: December 2007

The H9 well in Morecambe Bay was drilled in Block 110/2a to a total depth of 18,009 ft at true vertical depth of 3484 ft, giving a step-out ratio of 5.17. This represented a record step-out ratio for this area and was achieved using water-based drilling fluids. This achievement was made possible by careful planning, good drilling practices and the judicial use of lubricants.

Normally an oil-based mud (OBM) would be used for a well of this type; however the field is in shallow water, close to shore in an environmentally sensitive area, precluding the use of OBM.

Rotary steerable tools were employed to maintain the well path within a very thin (17-ft) reservoir. A total of 8,891 ft was drilled in the reservoir section and the well path only exited the reservoir once for a short length before being brought back.

Although the well was planned to TD at 18,000 ft, it was not realistically expected to achieve over 15,000 ft. When drilling ceased, it was for geological reasons-the well path was dipped just prior to TD to assess reservoir thickness, which increased the torque significantly. Without this planned deviation, further drilling would have been possible.

This paper describes the planning process, the drilling practices and the fluid characteristics that enabled the well to be successfully completed.
Improved and More-Rapid History Matching With a Nonlinear Proxy and Global Optimization
Authors: Cullick A. S. , Johnson D. , Shi G.
Published: December 2007

The generation of reservoir simulation models that match field production data has been a long-time industry challenge. This paper presents two workflows for assisted history match. One workflow minimizes the misfit between simulated versus history data with a global optimizer, by adjusting reservoir and well unknown parameters in the simulation model. An alternative workflow is used to reduce the number of numerical simulations. The workflow trains a comprehensive nonlinear proxy model with a small set of numerical simulations from experimental design. The nonlinear proxy neural network is used to characterize parameter sensitivities to reservoir parameters and to generate solution sets of the parameters that match history. The neural network solution sets can be validated with the simulator or used as initial solutions for a full optimization. The paper demonstrates that the neural network is an excellent proxy for the numerical simulator over the trained parameter space. A field example from a water injection project illustrates the approach with excellent matches for individual well fluid rates, using a number of reservoir and well parameters. The use of the proxy yields excellent matches for well production profiles.
Transaction Costs and Risk Preferences: Modeling Governance in Offshore Drilling
Authors: Jablonowski C. J. , Kleit A. N.
Published: December 2007

This research examines oil companies' decision to vertically integrate into the drilling function within a transaction cost economics framework. Risk preference is also investigated as an explanation for organizational choice. Econometric models are specified and estimated for organizational choice and for the underlying cost functions of competing organizational forms. Estimation of the cost functions permits isolation of the effects of transaction attributes to each form of organization, shedding light on the relative impacts of hazards of exchange and internal costs. Results provide support for both the transaction cost and risk preference hypotheses as determinants of organizational form. The cost functions also enable estimation of the incentive gains of outsourcing and the avoided transaction costs due to organizing activities internally.
Slimhole Drilling: An Economic and Effective Answer to the Development of Previously Known "Uneconomic Reserves"
Authors: Khan Hasnain Ahmad , Sajid Hafiz Lutf-ur-Rehman , Zahid Salman
Published: December 2007

The economics of exploration and production (E&P) continue to encourage use of new methods to reduce costs. Slimhole technology is one such method which offers effective cost reduction by reducing; equipment size, tubular costs and environmental impact.

The technology is a proven alternative to conventional drilling operations. Since it is now technically feasible and economically viable to produce from smaller well bores. It has become a realistic alternative to the development of previously known uneconomic reserves. Also extensive application in exploration has validated the use of disposable slimhole wells to improve seismic data interpretation.

Currently the E&P industry faces the challenge of increasing production to meet growing energy needs. Many proven reserves remain unexploited due to unfavorable economics (e.g. small size, remote location). A reduced cost slimhole drilling plan can put these reserves to production. This paper outlines the application of slimhole technology to the development of such reserves which cannot be developed using conventional drilling. Cost reduction, which is heavily influenced by hole size, is a major factor prompting the application of slimhole technology to development of small reserves.

This paper provides economic comparison between slimhole technology and conventional methods of exploitation. It also outlines a strategy to identify and produce smaller reserves using slimhole as an effective technique for enhancing exploitation economics.
Use of Reservoir Simulation for Optimizing Recovery Performance of One of the Iranian Oil Fields
Authors: Taheri A. , Sajjadian V. A.
Published: December 2007

A black oil reservoir simulator has been used to determine the reservoir management and production strategies to optimize the oil recovery from an offshore low porosity, low permeability carbonate reservoir with permeability of 1-3 md and porosity of 5-20%. This reservoir is a candidate for an EOR process, because the reservoir production rate has been declined rapidly to about half of the initial production rate within four years. The injection techniques that were used in this study include: (1) water injection, (2) gas injection, (3) water alternating gas injection (WAG), (4) simultaneous water alternating gas injection (SWAG), (5) gas injection in the top of the reservoir with water injection in the reservoir bottom and (6) gas injection in the bottom of the reservoir with water injection in the reservoir top. Specific strategy that was used includes the use of horizontal injectors and producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. Simulation results show that the most economical method to produce this reservoir is WAG. This production strategy has resulted in better efficiency and therefore higher oil recovery and good economics.
Beyond the Limits of Drilling and Completion—Expandables
Authors: Mawford Nick , Stephenson David , York Pat , Rosenberg Steve
Published: December 2007

Drilling trouble zones has haunted drilling operations experts through the years. Conventional methods for mitigating formation problems encountered during the drilling phase of a well, such as unstable formations, overpressured formations, and loss zones, are often costly and ineffective. Age-old methods of simply setting a casing and drilling ahead with a different mud weight and a smaller hole size are becoming increasingly unacceptable as the industry strives to reach deeper reserves.

The use of cement, chemical "cocktails," and loss-circulation materials can significantly increase well costs. Using conventional solid expandable drilling liners which are tied back to the previous casing can also be cost prohibitive and lead to non-standard equipment requirements for the following section of the well.

This paper explains how a non-cemented, solid expandable open-hole clad can be installed remotely from a previous casing to isolate problem formations so that the target setting depth can be reached with conventional casing, without sacrificing hole size.

Installation of a solid expandable open-hole clad will result in mitigation of problem sections and allow drilling to continue with the same hole size. The problem formation is straddled with a short length of expandable casing or clad with a resultant drift ID equal to the diameter of the original hole or drill bit. With this full bore ID, further clads can be run through, and deployed lower in, the same hole section.

In addition to reducing operational risks associated with expanding long lengths of conventional tied-back solid expandable open-hole liners, the open-hole clad or "Steel Mudcake" significantly reduces well costs and results in higher and earlier production associated with the increased hole size in the reservoir section.

Open-hole patch systems have been used extensively with excellent results in carbonate formations, in remote locations over the past 20 years. This type of system is expected to have a significant effect on the global drilling industry because it will allow downsizing of conventional casing designs by eliminating conventional and expandable contingency casing strings without sacrificing completion and production performance. This advantage allows the operator to drive down well costs by minimizing the well's "flat" time on the drilling curve and using conventional long, tied-back expandable drilling liners.
A Novel Model for Viscoelastic Fluid Flow in Porous Media
Authors: Garrocuh A. A. , Gharbi R. B.
Published: December 2007

Steady-state flow experimental data have been analyzed for two commonly used polymers representing two generic classes: polysaccharides (xanflood), and partially hydrolyzed polyacrylamides (pusher-700) flowing inside bead packs and Berea sandstone. Oscillatory flow measurements have been used to compute the polymer solution's longest relaxation time (θf1) which is referred to as the characteristic relaxation time in this paper. Steady-state flow experimental data for the two polymers combined with measured polymer viscous properties have been converted to average shear stress-shear rate data inside porous media. An average power-law exponent (n¯) is therefore obtained for the polymer flow inside porous media. Using and θf1, and n¯, rock permeability (k) and porosity (ϕ) and fluid flow velocity (u), a viscoelasticity number (NV) is calculated, and found to strongly correlate with the pressure gradient inside porous media. This correlation is the basis for defining a viscoelastic model for polymer flow, analogous to Darcy's law. The proposed model asserts a non-linear relationship between fluid velocity and pressure gradient. It accounts for polymer elasticity, and for pore geometry changes due to molecular adsorption and mechanical entrapment.
Independent Real-Time Quality Control of Directional Survey Data—Adding Value and Improving Safety on the Norwegian Continental Shelf
Authors: Nyberg Runar Kolseth , Håvardstein Stein Tjelta
Published: December 2007

Data quality is a number one priority when using data for real time decision making. Independent quality control is the key element for good reservoir and safety management. The concept of independent QC shows how gross errors and poor tool performance could easily be detected. Approximately 94%1 of the wells drilled showed some kind of gross errors and most of these were resolved without any loss of rig time.

The in-house developed Survey QA/QC application connects to the service companies’ WISML servers, and retrieves standard parameters and detailed magnetic survey data information.

Standard parameters are streamed directly into the Directional Drilling Database, preventing mistyped survey data being presented and used.

The detailed magnetic survey data is processed in the Survey QA/QC application where lack of quality is highlighted.

If the data quality requirements are not met, the asset's Directional Drilling Surveying Specialist will discuss with the service company representatives and decide if any further action is required. This close interaction between operator and Service Company increases the potential to learn from each other and overall achieves a better service and common understanding. This however does not alter lines of responsibility
Managing Sustainable Annulus Pressures (SAP) in Adco Field
Authors: Al Hosani Hasan
Published: December 2007

Managing Sustainable Annulus Pressures (SAP) is one of major well's integrity challenges in the oil & gas industry as they pose an HSE concern.

As the wells ages, more wells do exhibit SAP of a varying degrees, some could be managed, and others should be dealt with on fast track basis & send to work over (if required).

The objective of this paper is to provide an overview of ADCO's initiatives in managing casing sustainable annuli pressure in ADCO field.

Since the introduction of ADCO SAP guidelines in June 2002, to manage casing annuli pressures and ensure the integrity of all wells during their life cycle, ADCO field embarked on an aggressive campaign to implement the guidelines and manage SAP wells effectively.

The paper sheds light on how the SAP wells are being managed, base line data collection, integration with PIES (Production Injection Export System), SAP current status (compared with that recorded in early 2003) and associated KPI's.

And finally touch on recommendations & way forward based on ADCO massive experience gained during the last 3 years to ensure the integrity of all ADCO wells.
Faster, Longer, and More-Reliable Bit Runs With New-Generation PDC Cutter
Authors: Clegg J.
Published: December 2007

A new process for manufacture of Polycrystalline Diamond Compact (PDC) cutters creates a wrapped thermostable region across the face and around the periphery of the diamond compact. This differs significantly from existing first-generation thermostable product as the treated region has complex geometry in three dimensions. This paper describes the new geometry of the cutters and shows how the thermostable region supports the cutter as it slowly wears. It also shows how the onset of wear into the tungsten carbide substrate behind the diamond layer is delayed significantly.

Laboratory test results show a 270% improvement in abrasion resistance over premium PDC material and field case studies show how the new cutter type has saved money while drilling and allowed PDC bits to drill sections that previously required multiple bit runs.

Case studies are presented from a variety of applications around the world including hard and interbedded formations and abrasive sands. They compare direct offset runs with existing, first-generation thermostable data.

The new-generation thermostable cutter stays sharper, for longer, than either the first-generation thermostable cutter or previous non-thermostable PDC material. It will allow development of lighter set and more aggressive bit designs able to set new standards in speed, steerability and stability without having to sacrifice durability in the design.

New cutting material developments are at the forefront of the ongoing improvement of PDC bits. This is a significant development that shows a step change in cutter and bit performance. It allows for the realization of a new generation, not just of cutters, but also of bit designs.
Cost-Effective Life-Cycle Profile Control Completion System for Horizontal and Multilateral Wells
Authors: Ogoke V. , Aihevba C. , Marketz F.
Published: December 2007

A new cost effective life-cycle profile control completion system has been developed to solve major problems associated with surveillance and interventions in horizontal and TAML level 2 multilateral wells completed with ESP.

As fields age and produced water oil ratio increase, surveillance and profile control in the multilateral wells drilled in PDO have become a major challenge. These wells are TAML level 2 multilaterals. Production from two to nine barefoot lateral legs is commingled and artificially lifted by electrical submersible pumps (ESP). ESPs prevent through tubing access to the laterals. Installation of a Y-tool allows for wireline (WL) or coiled tubing (CT) deployed logging and some remedial CT intervention. Well and reservoir management challenges arise from completion design limitations such as barefoot completion, commingled production, the presence of ESPs, access to the TD of the backbone and inability to selectively re-enter the laterals.

New minimum-cost zonal isolation and downhole control technologies provide an opportunity to retrofit TAML level 2 multilateral wells for well and reservoir management purposes. Swelling elastomers in the form of the expandable zonal inflow profiler (EZIP) tool allows segmentation of wellbore section into a discrete number of management intervals. Interval control valves provide the capability to shut-off water or gas.

This paper describes the design and application of remotely operated selective EZIP completion technology (SECTOR) in TAML Level 2 multilateral wells in the carbonate reservoirs of Qarn Alam Asset of PDO. With SECTOR, existing TAML Level 2 multilateral oil producers are converted to TAML-5 multilateral wells. The lateral legs are isolated from each other and can be selectively produced, shut-off or stimulated. The need for CT interventions for production logging and water shut-offs is removed. The water shut-off process offered by this technology is reversible.
Three Statistical Pitfalls of Phi-K Transforms
Authors: Delfiner P.
Published: December 2007

Phi / k transforms are widely used to predict permeability. Some of the difficulties of this exercise are well identified, such as the homogeneity of the population (rock typing), the matching of cores and logs (especially depth matching), and the problem of permeability upscaling. Not so well known, however, are the pitfalls of a statistical and geostatistical nature that may create significant biases, always in the same direction, an underestimation of permeability.

The passage from Phi to k is performed in three steps:

(1) in cored wells, an exponential regression equation is established between core porosity and core permeability k; (2) in uncored wells, log porosity is used instead as input; (3) the same equation is sometimes used again to populate the cells of a dynamic reservoir model in 3D, where input porosity values are obtained by interpolation.

The core-scale regression equation generally underestimates permeability by at least a factor of 2. The origin of the bias lies in the reverse transformation from logarithmic to arithmetic scale. To avoid this pitfall a new permeability estimator is proposed, based on the quantile curves of the Phi / k crossplot. This estimator is data-driven and does not a priori assume any particular functional relationship between Phi and k, such as an exponential regression function.

One of the simplest diagnostic tools to check the agreement between log and core porosity is a crossplot of one against the other. In the absence of bias the points are expected to be distributed along the Y = X line. In reality they are or they are not, according to which variable is plotted along the X axis. This apparent paradox is elucidated by bivariate regression theory and related to the difference of investigated volume between core and log data.

Direct input of upscaled cell porosity into an exponential core-scale permeability transform amounts to forcing geometric permeability averaging, which may again lead to serious underestimation of the true upscaled permeability when heterogeneity is significant.
Fault Leakage Potential Analysis in the Cantarell Field, Mexico, Using Geomechanics
Authors: Celis E. , García-Hernández J. , Morales-Ramírez J. M. , Cabrera-Toledo C. , Sheridan J. , Ward C. , Wiprut D.
Published: December 2007

Petróleos Mexicanos (PEMEX E&P) and GeoMechanics International Inc. (GMI) worked together to define the potential for fault leakage in the Sihil and Frontal faults of the Cantarell and Sihil Fields, Mexico. Water production with a low salinity content in the northern area of the Akal block in the Field seems to be derived from neighboring blocks of Tertiary age and not from the water leg of the reservoir. Pore pressures in the reservoirs from the Akal block have depleted significantly since production started in the late seventies. Nitrogen injection started in the late nineties and has contributed to pressure maintenance since then. Overpressures in the shale layers above the reservoirs have been identified. A number of studies have shown that shear failure along reservoir-bounding faults can increase fault permeability and compromise fault trap integrity. The orientation of a fault and the magnitudes of the present-day stresses and pore pressure acting on the fault will determine whether the fault has the potential for shear failure and therefore a potential for leaking. The analysis of fault leakage potential was based on a geomechanical model covering the northern area of the Cantarell Field and its changes with time due to reservoir depletion and nitrogen injection. Information from wireline logs, downhole tests and drilling events from eight wells drilled between 1979 and 2005 were used to build the geomechanical models that change with time. The principal effective stress model (the magnitudes and orientation of the principal stresses), and the mechanical properties model were defined and validated with image logs, caliper logs and drilling experiences before their use for fault leakage potential analysis. Specific sectors of the two faults appear to be tectonically active during the production history and therefore had potential to leak. Fault leakage potential may explain water production with low salinity content in the northern area of the Akal Block in the Cantarell field.
Streaming Potential Applications in Oil Fields
Authors: Chen M.-Y. , Raghuraman B. , Bryant I. , Supp M.
Published: December 2007

Two successful field tests of streaming potential measurements in oil fields have been carried out: one in a horizontal oil production well and one in a vertical water injection well. Pressure transients were created and the streaming potentials generated by these transients were measured by arrays of permanent electrodes placed in the boreholes. The electrodes are partially insulated from the other completion components but nonetheless record high signal-to-noise ratio responses. These field experiments have demonstrated that the streaming potentials arising from pressure transients can be measured accurately under borehole conditions. Numerical methods have been developed to interpret these measurements to offer distributed characterization of matrix permeability at various depths of investigation and effective fracture transmissibility.

While streaming potentials have been observed in many laboratory rock experiments, we believe these are the first streaming potential transients to be measured in an oil field. The field experiment results, together with forward and inverse modeling studies, indicate many possible applications of transient streaming potentials in oil and gas fields for reservoir characterization and reservoir monitoring.
Planning and Identifying Best Technologies for ERD Wells
Authors: Gupta Adit
Published: December 2007

This paper on ERD wells focuses on nearly all important aspects of drilling ERD wells. Various case studies have also been taken while discussing various aspects so as to signify the practical experience of ERD wells. The latest technology for drilling ERD wells has been taken up. This paper will discuss the planning of ERD wells, the latest technology for ERD wells, the consideration of drill pipes and drilling fluid design for ERD wells, completion of ERD wells, well control and fishing and workover tools for ERD wells.

At the end, suggestions have been given so as to get better results for ERD wells.