bluuebunny/crossref_metadata_2025 huggingface dataset:
Slag Cementing Versus Conventional Cementing: Comparative Bond Results
Authors: Silva M. G. P. , Miranda C. R. , D’Almeida A. R. , Campos G. , Bezerra M. T. A.
Published: December 2007

The first publication on the use of slag as a material capable of substituting the traditional Portland cement in well cementing appeared in 1991, when it was seen that it could be added to drilling fluid and solidify it with some advantages over traditional methods.

As a result, only recently, the use of this emerging technology has been suggested for situations where difficulty in removing the drilling fluid mud cake has been expected, as in HP/HT wells, for example. In this case, the practical rules for a successful cementing operation cannot always be implemented.

As these high temperature wells are fundamental to the exploitation of important Brazilian fields, it was decided, as one of the strategies for overcoming the difficulties in obtaining good cementing results, to invest in evaluating the performance of the slag-mix technology.

An extensive research project has therefore been conducted in a large-scale wellbore physical simulator, with the principal objectives of investigating the ease or difficulty of mixing the slag-mix and to evaluate the bond quality obtained after cementing and acidizing the well. Thus, the object of the present paper is to investigate the performance of slag-mix slurries under three distinct scenarios: cementing surface casing; cementing production casing at medium temperatures; and cementing production strings at high temperatures. The resistance of the set slurry to the attack of HCl / HF is measured in a physical simulator under static and dynamic conditions.
Drilling Optimization Software Verified in the North Sea
Authors: Bratli R.K. , Hareland G. , Stene F. , Dunsaed G.W. , Gjelstad G.
Published: December 2007

This paper presents the introduction, application and verification of a new drilling optimization approach. During the past decades rate of penetration (ROP) models for all types of drilling bits were developed and verified. The unique software uses these models in a new approach that optimizes the drilling cost on each hole section. The simulation of ROP every foot gives the capability to simulate the effects of all operating conditions, bit design, bit wear and formation properties.

All the penetration rate models used can be inverted to solve for rock strength if ROP, operating conditions, lithology percentage and field reported bit wear is known. This imply that if one well has been drilled, and the penetration rates are inverted, a foot by foot strength is obtained, by integrating over each individual bit run until the field reported bit wear matches the calculated. This strength is then used as input for simulation, and it is shown that the drilling cost for one particular 12,25" section can be reduced as much as 45-50 percent by changing bit design and operating conditions.

This approach has been verified with North Sea data where the generated rock strength from the 12,25" section has been used as input to simulate the ROP and rotating time. These simulations compare well with the measurements of ROP, made in the two following wellbores drilled in the same field. Simulating ROP using drilling data from a well in a nearby field also gave promising comparisons.

Introduction

The DRilling OPtimzation Simulator (DROPS) is developed to reduce the cost of future wells based on a Geological Drilling Log (GDL), created from the data collected in a previous well drilled in the same area. The GDL is created using ROP models inverted to calculate rock compressive strength. The simulator has the capability of simulating any combination of operating conditions, bit designs, pull depths, hydraulics, WOB and RPM. The basic idea behind DROPS is to simulate the drilling operation prior to the actual drilling, and to find the optimum cost level. Simulations to verify the software (drill behinds) have been performed using actual field data from the North Sea, provided by Saga Petroleum ASA, well A and B. Data from well C, provided by Statoil, have also been used in the drill behind simulations. The simulated ROP results from the drill behind compares well with the results for actual measured ROP and cumulative rotating time, which are promising for further development and application of the method. Based on the comparison some cost optimizations for future wells in this region have also been performed. The cost reductions obtained indicate potential cost savings of 45-50 percent of total drilling cost per well, compared to the current industry practice in the area. By using this methodology in the planning process the most cost effective drilling program can be obtained.
Tools for Predicting and Avoiding Gas Migration after Casing Cementing in Brazilian Fields
Authors: Martins A. L. , Campos G. , Silva M. G. P. , Miranda C. R. , Teixeira K. C.
Published: December 2007

The occurrence of gas migration problems in several oilfieds in Brazil, motivated an experimental computational study conducted on PETROBRAS R&D Center. Lab and pilot scale equipments were used to define basic guidelines for the success of a cementing operation in front of gas zones. The necessity of a team work, involving lab, design and operation teams is emphasized. This joint effort aims the optimization of well conditioning, slurry design and displacement programs. Adequate evolution of gel strengths and consistency, pseudoplasticity and minimum fluid loss and free water are the main variables for optimum slurry design. Analysis of historic cases of cementing failures help in the establishment of operational guidelines for future jobs
Core-Data Management for Reservoir Characterization Studies
Authors: Sombra Cristiano L. , Sarzenski Darci J. , Derraik André L. B. , Hester Anna M. , Borges Renato F. , Ierusalimschy Roberto
Published: December 2007

Core-analysis data, either qualitative (i.e., lithology, grain size, oil staining, facies, diagenetic attributes) or quantitative (i.e., porosity, permeability, fluid saturation, petrographie quantifications), can be input data for formation evaluation and reservoir characterization procedures, such as log calibration, variogram modelling, search for analogue outcrops, etc. The quality of reservoir 2D and 3D models, such as volumetric analysis and stochastic modelling, depends on core information.

A major challenge while using core data to calibrate electric logs is to achieve the most precise matching between different depth scales. In thinly stratified reservoirs, small differences in depth can produce significant distortions on property correlations. Moreover, an effective calibration exercise depends upon handling a series of parameters altogether, and mathematic procedures seem to fail in many commonly used situations. Digitalization of core descriptions through an interactive graphical interface, based on the idea of core objects, brought an efficient solution to this problem. A continuous piece of core, with all the geological descriptions, sampling and laboratory quantifications related to that interval, defines a core object. The most usual information associated to that object are grain size, lithology, texture, oil staining, cementation, plug porosity and permeability, minipermeametry measurements and core-gamma readings, all of which being graphically edited and visualized. Moving core objects up and down will adjust them to electric log curves, what will guarantee consistency between these two data sources.

After core and log data are matched, they can be exported as output files to any log analysis package or to a statistical package, on which more sophisticated log calibrations are achieved These output files can be useful for many distinctive reservoir characterization applications, some of which are discussed in this paper: basic statistics and regression analysis from core data, core-log calibration, cut off determination, outcrop versus subsurface analogy, variogram modelling and calibration of acoustic properties.
Important Issues in Cuttings Transport for Drilling Directional Wells
Authors: Azar J. J. , Sanchez R. Alfredo
Published: December 2007

There are many factors that impact on hole cleaning while drilling directional wells for hydrocarbon recovery. Those that are most prevalent include: annular drilling fluid velocityhole inclination angledrillstring rotationannulus eccentricityrate of penetrationdrilling fluid propertiescharacteristics of drilled cuttings

In this paper the authors discuss the above factors and their field limitations. In addition, the key issues that need to be addressed for the development of a universal and reliable model in hole cleaning are identified.
A Generalized Methodology for Minimum Miscibility Pressure
Authors: Ahmed Tarek
Published: December 2007

This paper presents a generalized methodology for predicting the MMP required for the multi-contact miscible displacement of crude oil systems by gas injection. The approach is based on applying the Peng and Robinson Equation of State; in a modified form, in conjunction with a newly introduced "Miscibility Function". The miscibility function is designed to provide accurate predictions of the MMP. It is the objective of this paper to demonstrate how this miscibility function can be used to determine the necessary conditions required for miscible displacement of hydrocarbon systems by gas injection. The validity and the use of the proposed methodology is illustrated by matching several experimentally measured minimum miscibility pressure values.
Computation of Wag Process and Experimental Verification of Fractional Flow Hysterisis in Porous Media
Authors: Cunha M.C. , Bonet E.J. , Correa A.C.F.
Published: December 2007

We present a methodology for computation of the water alternated gas (WAG) injection process for oil recovery. In this methodology we use the method of characteristics to construct the analytical solution of the displacement, and we design a computer program to perform the intermediary steps required for the effective calculation of the solutions. We also analyze the effect of the hysterisis phenomenon on the fluid displacement in porous media, due to the sequential imbibition and drainage process. In our analysis we use published analytical hysteretical models and experimental results acquired in our laboratory apparatus. The comparison between experimental and analytical results are presented.

Introduction

Water-Alternate-Gas is an effective process to enhance oil recovery. The process is modeled by a system of hyperbolic partial differential equations; the conservation of water-hydrocarbon phase and the conservation of the gas component. As it is known, there are discontinuities in the solution of this kind of problems. Also the sequence of water and gas injection means that the boundary condition is a step function. Therefore, there are several jumps in the water saturation profile. Simulation of this process using usual numerical methods, such as finite difference and finite elements, is impractical, since the numerical dispersion near the jumps will propagate and interact themselves, destroying the character of the solution.

In this paper we describe a semi-analytical method to solve the WAG model.

We use the characteristic method to construct simple waves and the coherence principle to obtain compatible connections of simple waves that solve the Riemann problem, with arbitrary left and right states, for the model.

The effective calculations of the front trajectories, water saturations and gas concentrations are done by means of a computer code that perform the intermediary computations. On the other hand, the water-alternated-gas injection causes a sequence of imbibition and drainage process in the porous media. This process is the cause of the appearance of the hysterisis in the relative permeabilities curves, and in consequence, the hysterisis in the fractional flow curves. In this paper we also analyze the hysterisis effect on fluid displacement in porous media. We restricted our study to two-phase water and oil flow. Our hysterisis analysis is performed using experimental results, analytical formulation and calculation, and the comparison between experimental and analytical results.
Sand Production in Ultra-Weak Sandstones: Is Sand Control Absolutely Necessary?
Authors: Tronvoll J. , Papamichos E. , Skjaerstein A. , Sanfilippo F.
Published: December 2007

This study is focusing on sand production processes in weak sandstone formations with a uniaxial compressive strength in the range of 0 – 10 MPa, with special emphasis on the ultra-weak facies where uniaxial compression tests hardly can be conducted. The relative influence of rock mechanical properties on rock failure and sand production modes is addressed to understand sand production data from wells in a weakly consolidated basin. Results of physical model experiments of sand production from boreholes and perforation cavities as well as numerical simulations have been used along with the field data to evaluate different criteria for the onset of sand production in ultra-weak formations. It is shown how in particular the shallow and weakest strata deviates from the classical behavior of more competent formations, and a simple empirical criterion for estimation of the conditions for onset of sand production is proposed. Finally, alternatives to classical sand control strategies are discussed, which directly take into account the nature of weak sandstone.
Revitalization of Mature Reservoirs in Lagomar Segregation, Lake Maracaibo, Western Venezuela
Authors: Muñoz Pedro J. , Antunez Angel , Medina Mileida , Parra Nestor , Bengochea Xiomara , Agostini Nélida , Herrera Sol
Published: December 2007

The Lagomar production Unit covers Blocks I, II and XII of Maraven's concession in the Lake Maracaibo basin, Western Venezuela. The Unit consists of 114 reservoirs mostly of Eocene age, it has 740 wells drilled to date and has been on production for more than 40 years. The combined total OOIP of these reservoirs stands in excess of 8,487 MMSTB and at the end of 1996, 663 MMSTB remain as proven and 44 MMSTB as probable reserves. These substantial volumes of remaining reserves make the Lagomar Unit as one of the most attractive producing areas within Maraven's operating plan.

Until 1992, the Lagomar Unit had been on a steady decline mostly because of primary depletion and with limited efforts of secondary recovery. Detailed characterization of the reservoirs was lacking up to this time and the reservoir mechanism and the fluid movements, specially in terms of secondary recovery were not well understood. A revitalization program for increasing production and ultimate recoveries was undertaken at this time in the form of a multidisciplinary team effort. The team was charged with increasing the production and reserves over the following five years. The strategies included, a) recompletion of old wells, b) drilling of new wells including the re-entry and horizontal wells, c) commingled production of multiple horizons, d) slimhole, geologically targeted infill and appraisal drilling, e) reactivation of Basal La Rosa reservoir.

Implementing the revitalization strategies increased the drilling activity to 82 wells and 109 recompletions during 1992-1996. Directional drilling technology was successfully applied in the development well VLA-1035 and in the reentry sections of the wells, VLA-780 and VLA-807 in the VLA-6, C-7 reservoir. The productivity of Basal La Rosa increased from 3,000 to 19,000 STB/D. Commingling the production of C-2 and BLR reservoirs increased the production fourfold. The application of geologically targeted infill drilling (19 wells) and slimhole drilling (18 wells) increased the production output by another 20,000 STB/D.

The implementation of these technological alternatives favorably impacted the Lagomar production rate with an increase from 59,000 STB/D in 1992 to 81,000 STB/D in mid-1996. This paper describes the various strategies of revitalizing the Lagomar Segregation Unit and how these were implemented in a multidiscilplinary manner for achieving optimum results.
The La Rosa Basal Sand, Block I, Venezuela. Strategies and Expectations
Authors: León Alfredo , Casas Jhonny , Agostini Nélida , Bengochea Xiomara , Salamanca Lourdes , Muñoz Pedro , Parra Nestor
Published: December 2007

The La Rosa Basal Sand (Miocene), known in some areas as Santa Barbara Member, was discovered in 1954 as a pool for Block I area in Lake Maracaibo basin, with a relatively poor success during the next 40 years of production.

Since 1993 however, an aggresive policy of workovers and drilling was undertaken increasing by over 300 % the total production of medium and light oil. These activities were based upon the recommendations of several multidisciplinary team projects.

The La Rosa Basal Sand is a 5–60 ft thick sandstone deposited in a fluvio deltaic environment overlaying an unconformity which truncated Eocene succesions (Pauji and/or Misoa formations). Lateral continuity varies from south to north and it is feasible not only to observe new sand bodies but also coalescent effect with the underlying Eocene productive sands. The La Rosa Basal Sand is overlain by a 100′–200′ thick marine shale, known as La Rosa Shale.

Change of paradigm in the reservoir management was mainly a consequence of the result of well VLA-1185, upon the west flank of the Block which also demanded a revision of the petrophysical parameters. Its initial production of 1,300 BPD and 0.3 % water, was difficult to explain considering resistivity values of only 8–10 Ohm-m, a parameter which had been long considered to indicate high water saturation. Such parameter subestimated remnant reserves and in some cases supported rejection of some well locations. Additionally new core data has helped to better understand reservoir behaviour and predict future activities. During the last four years seismic interpretation, stratigraphic well by well correlation, structural and isopach maps and production history matching have been updated by information from new wells which have acted as a support for a slimhole campaign. Consequently, geologically targeted infill wells and no conventional workovers, increased production from 4000 BPD to 18400 BPD (Mid, 1996).
Three-Dimensional Multiphase Flow Simulation in Petroleum Reservoirs using the Mass Fractions as Dependent Variables
Authors: Maliska C.R. , da Silva A.F.C. , Czesnat A.O. , Lucianetti R.M.
Published: December 2007

This paper describes a numerical methodology for solving three-dimensional multiphase flow in petroleum reservoirs. The mathematical model encompasses the Darcy's equations and the mass conservation equation for the oil, gas and water components. To account for the gas phase appearance/disappearance, without employing special strategies, the method uses the mass fractions as dependent variables. The mathematical model uses boundary-fitted coordinates which permits to deal with complex reservoir boundaries and offers the opportunity of better representing curvilinear geological structures. The solution is fully implicit and includes the proposition of a well model for non-orthogonal discretization.

Introduction

The simulation of the multiphase flow of oil, gas and water in porous media are usually carried out using the saturation and pressure as dependent variables. However, there are thermodynamic conditions in petroleum reservoirs in which the gas is dissolved in the oil, but the gas phase is absent. Since the saturation is related to the existence of the phase, when the gas phase disappears, but the gas component is still present. in the oil phase, the numerical scheme must take into account the phase appearance/disappearance. To deal with this problem it is necessary to change the variables during the simulation, or to avoid the phase disappearance, keeping a residual value for the saturation. These strategies poses numerical difficults and may cause instabilities during the solution procedure.

One alternative for by-passing this problem is to use the mass fractions of the components as dependent variables, as done in Prais and Campagnolo and Britto. This guarantees that, in the case of the gas phase disappearance, the mass fraction of the gas component, representing the total mass of gas dissolved in the other phases, will be non-zero.

This paper presents a numerical method for solving 3D multiphase flow of oil, water and gas in complex reservoirs using the mass fractions as dependent variables and a fully implicit formulation. For handling the complex geometries of the reservoirs, a non-orthogonal boundary-fitted coordinate system is used. This type of structured discretization has been previously used by Maliska et al for modeling two and three phase flows with IMPES formulation. Curvilinear orthogonal grids have been used in the past by Hirasaki and O'Dell, Sharp and Anderson and Robertson and Woo among others.

The model is applied to solve three-dimensional two-phase and three-phase flows in petroleum reservoirs.
Computing the Effective Permeability by Finite Differences, Finite Elements, and Mixed-Hybrid Finite Elements
Authors: Ribeiro R.F. , Romeu R.K.
Published: December 2007

Upscaling the absolute permeability is a key operation in the reservoir characterization process. Although quick analytical estimates can be acceptable in some applications, numerical simulation is considered the reference method for the general case. This paper examines the performance of three numerical methods - finite differences (FD), finite elements (FE), and mixed-hybrid finite elements (MHFE) - on the computation of the effective permeability in coarse and refined numerical grids for some examples of heterogeneous media. Results show that the errors are systematic: the FD method underestimates and the FE method overestimates the exact answer in coarse grid discretization Averaging both estimates seems to compensate these errors. Although it follows the general behavior of the FD method, underestimating the exact answer, the MHFE method produces the best results for a given level of grid refinement or for a given size of the linear system.

Introduction

Modern geological and geostatistical modeling allows a reservoir heterogeneity description that is too much detailed to be directly handled by numerical flow simulators due to limited computing power. Hence, we have to compute effective or equivalent properties on a coarser grid, trying to keep the essence of the fine scale information for engineering purposes. This is known as the upscaling process, which has turned out a critical step for the reservoir studies. Among all properties to upscale, the absolute permeability has been the most studied.

The definition of the effective permeability, Keff, is not unique. The idea is to replace a heterogeneous permeability medium by a homogeneous one in such a way that the substitution is equivalent for certain purposes and situations - but not, in general, for all purposes and situations. Indeed, when we replace many data by one single data, we generally loose information, and the equivalence is only relative. Depending upon the selected criteria, the results of Keff may be different. At the end of this introduction, we will precisely state how Keff is defined in this paper.

There are two classes of methods for computing the equivalent permeability: analytical methods and numerical methods. Exact analytical solutions apply only for special cases, like in parallel and in series configurations. A more interesting case is the isotropic lognormal 2D medium for which the equivalent permeability is equal to the geometric mean. Some analytical results have been derived from perturbation methods or from the effective medium theory, which both involve special hypothesis. Different kinds of spatial averages provide quick estimates useful for many practical applications.
Integrated Horizontal Well Stability Design in Potiguar Basin
Authors: Ferreira F.H. , Siqueira C.A.M. , Martins J.A.S.
Published: December 2007

Problems related to wellbore stability can increase drilling and completion costs. At the limit it can be impossible to drill a well because of wellbore mechanical instability. Several wellbore stability simulators can be found in the literature. Some of them present very simplified analytical solutions while others are numerically complex. Besides choosing the simulator, it is necessary to know the elastic and strength properties of the rock, the in-situ stress field, rock porosity and permeability and original pore pressure. Determination of some of these input data are costly and sometimes impossible. This paper presents the data gathering and design of a horizontal well in the Potiguar Basin (fig. 1) in Northeast Brazil. The main goal of this work is the determination of the mud density to drill a horizontal well, safely and economically viable, in order to avoid wellbore collapse (inferior limit) and formation breakdown (superior limit).

Introduction

This paper presents an integrated wellbore stability design for drilling a horizontal well in the Potiguar Basin. An integrated wellbore stability analysis means data gathering and mechanical stability numerical simulation.

Underground rocks are always under a compressive stress field. When drilling a well, an amount of material is removed and consequently the wellbore neighborhood needs to support the load that was supported by the removed material. This new stress state may cause the wellbore rupture depending on the mud density and formation strength parameters.

Rock behavior is totally different if it is submitted to compressive or tensile loading. Because of this, it is necessary to consider two different failure criteria to properly represent rock collapse behavior (compressive stress state) and another to represent formation breakdown (tensile stress state). These two criteria are presented in Appendix A.

Field data and lab tests have provided the in-situ stress field and rock mechanical properties for the horizontal well stability analysis presented in this paper.

Fracture propagation and pressure decline were analyzed from step rate test (SRT) allowing the stress field evaluation. Unfortunately a minifrac was not scheduled for this field. Elastic and strength parameters were determined from triaxial (drained) and uniaxial compressive tests done by Rock Mechanics Laboratory at Petrobras Research Center (CENPES).

Fluid properties, rock porosity and permeability, were obtained through lab tests. The bottom hole static pressure was determined in field.

A Finite Element Method (FEM) simulator (AEEPECD) was developed at CENPES for mechanical stability analysis in plane strain problems - The material constitutive law was considered elastic-plastic. MTOOL and MVIEW were used as pre and post-processors, respectively.
ESP's In Cyclic Steam Injection Wells
Authors: Gonzalez R. , Brunings C. , Toussaint L.
Published: December 2007

Since 1993, Electrical Submergible Pumps (ESPs have been applied with excellent results in the cold production of heavy crudes (9.5 API) in about 70 horizontal wells in the hamaca area of the Orinoco Faja. Over the three year production life of these wells, production declinations due to natural and mechanical causes of up to 50 % have been observed.

As an alternative to increase the production to the original rate of around 1500 bpd, cyclical steam injection in conjunction with the ESPs has been proposed. This process will entail periodic injection of steam in vertical or deviated wells in the same reservoir as the horizontal wells in order to evaluate the performance of ESPs in the high temperature environment. This test will be conducted in the latter part of 1996 with the intention of applying the results to the horizontal wells during the fiscal year 1997.

The evaluation will be realized as a joint effort between CORPOVEN and CENTRILIFT as a part of their strategic alliance which is now in operation.

The technical paper will show the ESP designs, the evaluation program, and the results, while comparing the production rates and costs of cold vs. thermal production methods.

Introduction

Heavy and extraheavy crude oil has traditionally. been produced in both cold and hot production (cyclic steam infection) with pumping units as the artificial lift method These pumping units have been replaced in part by electrical submersible pumps. (ESPS) Initially its application was in horizontal wells in the Orinoco Belt extending this system to the traditional areas of heavy oil. Right now, there are more than eighty wells producing more than 50,000 bpd in cold production with ESPS.

The outcome obtained with the application of ESPS have been excellent. Rates per well of over 2,500 bpd (16.6 m3 /h) of 9.1 API of crude oil have been recorded; however, some of the horizontal wells did not perform as expected, due to formation damage caused by drilling fluids during the completion of the wells.

As a result, the action taken was to stimulate these low productivity wells. The first stimulations were chemical (HCL), getting initially good results by increasing the production of the well from 150–200 bpd (0.99–1.32 m3 /h) to 800 bpd (5.29m3 /h). This production lasted one to two months. The other stimulation applied was thermal (cyclic steam stimulation); the first test was made in the well FBA 18 from the Bare field of the Orinoco Belt. This well incremented its production from 150 bpd (0.99 m3 /h) to 900 bpd (5.96 m3 /h), keeping the same rate for four months (until the writing of this paper). This well started to produce with an ESP system and continued to produce with the same method specially suited for thermal operations.
Evaluation of Completion Techniques in Salem Formation Using Real Data Fracturing Analysis
Authors: Holekamp S. , Payne M.E. , Albi J.T.
Published: December 2007

Completion strategies and stimulation design are both vital to the performance of an oil well. In most cases these two are optimized, however, in many cases this is done separately. There are clear advantages to developing a completion strategy that includes the stimulation design. When the stimulation design is viewed as a "contingency plan" if the original completion strategy fails or is not optimized, the original completion can severely limit the stimulation design.

Real time diagnostics are used to evaluate two scenarios and compare only one of many issues relating to completion strategies and stimulation design.

Introduction

Two similar wells in the Salem Formation were fractured using pretreatment diagnostics to aid in treatment design. Well No. 1 was produced for 3 1/2-years prior to fracture treatment recovering a total of 9400 bbl of oil. Well No. 2 was completed and fractured prior to any production. Included are results of prefracture diagnostics in both cases and production history of both cases. The purpose of this paper is to evaluate completion strategy, job size, and treatment diagnostic techniques in this field considering the production, pretreatment diagnostics, and treatment execution.

It is an agreed upon fact that the single most influential factor in fracture growth is the stress profile of the reservoir. This stress profile is influenced by the properties of the rock and of the pore fluids. The rock properties cannot be significantly effected, however, we can effect the pore fluid properties. The well can be produced to reduce the pore fluid pressure hence reducing the effective stress on the rock. Depending on the porosity, permeability, and the changes of these parameters with depth this process can drastically change fracture growth behavior.

Discussion of Results

Well No. 1. The first well treated was produced for 3 1/2-years prior to Fracture treatment recovering a total of 9400 bbl of oil. The reservoir pressure was reduced from 800 to 650 psi. This reduction in pressure should have created an additional 78 psi stress contrast between the productive layer and the boundary layers. The response of the prefrac treatment in this case was almost "textbook." A very clear closure could be seen and the decline was indicative of a contained fracture with leakoff characteristics of a classic wall building fluid. A forward simulation was run based on the diagnostic tests and the pump schedule was revised and pumped. P. 17^
A Study of the Above Average Waterflood Recovery of the Richardson Berea Field, Calhoun and Roane Cos., West Virginia
Authors: Blomberg John R.
Published: December 2007

A conventional waterflood of the Richardson Berea sandstone will yield a much greater than forecasted oil recovery. The very low permeability upper portion of the sandstone was ever considered pay but obviously a large portion of the recovery in the waterflood came from this "non-pay". Similar situations may exist in other oil fields, especially old or lugged oil fields that may present economical future development potential.
Integrated Footage Contract Vs. Day Rate; Drilling Time and Cost Analysis
Authors: Jabbar A. , Saifaldeen M. , Thabet Sayed Abdul Rahman
Published: December 2007

In 1993, Qatar General Petroleum Corporation (QGPC) conducted a comprehensive review of its Offshore drilling operations and cost under the then existing day rate contracts for the three offshore jack-up rigs under hire. The results of the study indicated that substantial cost saving could be achieved through the implementation of integrated footage contracts, such that most of the hole sections are drilled under footage; giving the rig contractor footage incentives to drill vertical and deviated hole sections. Similar "integrated" footage contracts had been successfully employed by QGPC in their onshore operations (vertical wells) for several years.

In August 1994, the first integrated footage contract for Offshore Operations was implemented. Some 25 wells have been drilled and side-tracked under integrated footage contracts since. Following the success of the first footage contract, two subsequent additional jack-up rig contracts were awarded on a similar contract strategy.

The paper focuses mainly on the differences in rig charges, intangible drilling cost and overall drilling performance under the integrated and day work contracts, as most of the tangible cost have remained relatively constant.
Assessment of Application of Dynamic Kill for the Control of Middle-East Surface Blowouts
Authors: Al-Shehri Dhafer A.
Published: December 2007

This paper presents some results from research work1. The purpose of this work was to investigate and assess the potential of dynamic kill as a method for controlling blowouts from producing gas and oil wells. Only scattered and little previous work was done on dynamic kill, particularly in the areas of gas kicks and blowouts during drilling. Blowouts of oil and gas wells after completion and starting production have received much less investigation.

In this work, a new dynamic kill model was developed for controlling surface induced blowouts of oil and gas wells. The model simulates multiphase flow in a blowout and relief wells. Dynamic simulation is performed for both kill through a relief well and through in-well surface injection.

The simulator makes use of proven multiphase flow models. Several assumptions and improvements are added or included in these models to account for flow geometry, temperature variation in the flow conduits and the effect of sonic flow closer to the surface.

The simulator predicts and links the expected reservoir performance with wellbore hydraulics. The effects of introducing the kill fluid into the well stream are also simulated.

Relief well dynamic kill simulations can predict the minimum injection flow rate into the relief and blowout wells, initial and final kill fluid densities, size and type of drilling string requirement for achieving the required kill rate(s) in the relief well(s), and horse power requirements. Simulations can also check for ability to inject at the desired rate through the formation. In the case of in-well kill, the model can be used to determine the optimum location of the point of kill fluid injection.

The model results were in agreement with data presented in the literature and from Kuwait field measurements.

The simulator leads to a much better level of understanding of blowout behavior and the potential of dynamic kill to bring gas and oil blowouts under control.
Kuwait Post-Capping: The Return to Production
Authors: Ali-Hussain A. , Drury G. J.
Published: December 2007

The recovery of oil production in Kuwait following Liberation required the tremendous efforts of many people. With regards to the oilfields, the initial phase of the recovery process was to shut-off all of the blowouts. This task was on a scale far beyond any other that the industry had ever seen. Specialized firefighting teams composed of both local KOC employees and Industry experts from around the world were assembled to tackle the huge task. These firefighting teams received much attention as the world watched their progress to control an event that impacted the environment of many nations However, following the successful completion of the firefighting teams there remained the second phase. This phase consisted of the monumental task of returning the oilfields to production. The efforts and accomplishments of this phase are not widely known It is the focus of this paper to highlight the various techniques incorporated to salvage the damaged wellheads and casing strings and where possible return these wells to production. This work will include the broad range of well types that are present within Kuwait, ranging from low pressure to high pressure (15M psi) completions. Additionally, the work consisted of various phases which included both rig and rig-less operations It should be highlighted that the damage to each well was unique with some wells requiring only minor repairs to the extensively damaged wells which required wellhead removal, splicing of casing strings, fishing operations, and recompletion. To further complicate the process, the work was conducted in an environment that was less than optimum with the presence of H2S. extreme desert temperatures, oil-ladcn soil, and unclcarcd minefields This work is equaled only by the tremendous accomplishments of the initial firefighting phase.
Mode Localization May Explain Some of BHA Failures
Authors: Yigit A. S. , Al-Ansary M. D. , Khalid M.
Published: December 2007

A Finite Element Model is developed for investigating the BHA dynamics. The stabilizers, WOB, and gravity effects are considered. The natural frequencies as well as the mode shapes are obtained through modal analysis. The results show that in certain drillstring configurations a small amount of parameter variation (disorder) may cause what is known in structural dynamics literature as "mode localization". If the modes are localized, vibrational energy is confined to small geometric regions instead of being propagated. This in turn results in very large amplitudes at certain locations which are not predictable through analysis of the nominal system. A field case is used to demonstrate the occurrence of this phenomenon under realistic conditions. Several operational and design methods to avoid the occurrence of mode localization are suggested.
The Drilling Optimization Performance in Kuwait's High Pressured Wells
Authors: Al-Sarraf Adel , Hazel Richard A.
Published: December 2007

Since the spudding of the first well in the Burgan Field in 1937, continuous improvements have been made in the drilling of wells in Kuwait. This paper will address the drilling optimization performance that has occurred during the development of the deeper high pressured formations.

Continued optimization performance in the deeper high pressured wells has proved to be the greatest challenge as a result of the adverse geological environment that has had to be addressed while drilling. This adverse geological environment consists of salt/anhydrite sections where formation pressure nearly equals fracture strength, pressure reversals, highly fractured thief zones and the presence of H2S.

While there was some earlier deep drilling in Kuwait, development of the deeper high pressured horizons began in earnest in the early to mid 80's and is still ongoing. Four major field studies will be addressed in the paper which encompasses the majority of the deeper high pressure drilling activity. The inherent problems that had to be overcome, the solutions that were found and the problems still to be faced will be depicted in this paper.

Abduliyah Field drilling has improved by a reduction of 77% in drilling days over a 12 year period. Magwa Field drilling has improved by a reduction of 58% in drilling days over a 10 year period. Minagish Field drilling has improved by a reduction of 74% in drilling days over a 14 year period. Umm Gudair Field drilling has improved drilling by a reduction of 72% in drilling days over a 13 year period. Total well depths for the above fields has ranged from 11800' to 16800’

Improvements which will be detailed in this paper will include well design changes, methods dealing with lost returns, mud cap drilling, bit optimization, and others.
7" Monobore Completion Design for Qatar's Offshore North Field
Authors: Martin Ben L.
Published: December 2007

Producing gas from the Khuff formation in Qatar's offshore North Field presents several completion design challenges. The North Field Khuff formation is a competent limestone / dolomite that is estimated to contain a GIIP of 504 x 1012 scf (504 TCF), which makes it the largest single accumulation of natural gas in the world. The North Field Khuff gas contains hydrogen sulfide and carbon dioxide concentrations of approximately 5,000 ppm and 2.5 mole percent, respectively. Initial condensate yields exceed 40 bbl/MMscf. For design purposes, brine water production was taken into account when making the metallurgical choices for the completion equipment. The producing interval, Khuff K-4 at a datum of 9,400 ft. subsea has a bottom hole temperature of 222°F, and an initial shut-in bottom hole pressure of 5,265 psi. Actual well deviations range from vertical to slightly over 60° from vertical, but all completion equipment was designed and tested to function properly in horizontal wells. The monobore completions have also been designed to accommodate high rate and high volume HCI acid stimulations that are performed during initial completions, and that may be needed throughout the life of the field.

Qatar's North Field monobore completions have been designed to accommodate all of the above well conditions under all expected wellbore load cases, while providing years of trouble free service.

This paper describes the wellbore and equipment design concepts utilized, the equipment innovations made, the equipment installation philosophy and results, and the equipment performance realized to date for the monobore completions in Qatar's offshore North Field.
Control of Microbiological Activity in Biopolymer-Based Drilling Muds
Authors: Ezzat A. M. , Rosser H. R. , Al-Humam A. A.
Published: December 2007

Water-based drilling mud formulations routinely include organic polymers as viscosifying and fluid loss control agents. These organic polymers, which are generally of either plant or microbiological origin (hence, "biopolymers"), can be degraded and utilized as nutrients for growth by naturally-occurring oilfield bacteria. This may occur despite the inclusion of biocide in some polymer preparations. Microbial growth in the mud can result in contamination of the well and near-wellbore zone. Fouling, corrosion and reservoir souring may then occur during subsequent operations. If growth in the mud is extensive, significant biopolymer degradation can be expected, with consequent loss of the mud's rheological properties. In these circumstances, additional polymer must be added to the contaminated drilling mud in an attempt to maintain viscosity and prevent excessive fluid loss. As additional biopolymer is added, and biodegradation continues, the cost of the drilling mud increases.

This paper addresses the requirement for control of microbiological activity in water-based drilling muds representative of those used in Saudi Arabia. A laboratory investigation of the relative efficacy of alkaline pH (lime) and biocide (glutaraldehyde) treatments in limiting microbiological activity in drilling muds is presented, and minimum treatment levels for absolute control of general aerobic bacteria (GAB) and sulfate-reducing bacteria (SRB) are provided. Application of these findings can be expected to minimize drilling mud biodegradation, and costly post-drilling operational problems such as production tubing and pipeline corrosion.
Minimization of Vertical Migration of DNAPLs Using Surfactant Enhanced Aquifer Remediation at Neutral Buoyancy
Authors: Shook G. Mike , Kostarelos K. , Pope G. A.
Published: December 2007

Remediation of water-bearing formations contaminated by organic liquids continues to be a challenge faced by both the public and private sectors.3 Chlorinated solvents such as trichloroethylene (TCE) are especially troublesome since they are denser than water and tend to migrate downward below the water table. Dense organic liquids such as this are commonly referred to as dense nonaqueous phase liquids (DNAPLs) and are particularly difficult to locate and remove from aquifers. 11 Surfactant Enhanced Aquifer Remediation (SEAR) has recently been shown to be an effective method for remediating chlorinated solvents from alluvial aquifers, but in aquifers without a proven aquiclude there are serious concerns about the risk of further downward migration of these solvents when the interfacial tension is reduced by the injected surfactant. To address this concern, we have developed a new version of SEAR called neutral buoyancy SEAR that minimizes this tendency and is especially targeted at those aquifers without a sufficient capillary barrier such as impermeable clay below the contaminated water-bearing formation.
Concentric Drilling Risers for Ultra Deepwater
Authors: Herrmann R.P. , Shaughnessy J.M. , Beynet P.A.
Published: December 2007

Use of a higher pressure rated riser run inside the marine drilling riser would provide floating rigs with some advantages enjoyed by fixed rigs; the potential to drill underbalanced or near balanced, improved gas handling capability, improved well testing capability, expanded kick control capabilities and increased mud weight rating. Drillers have found areas in ultra-deepwater where the fracture gradient is close to the pore pressure within a few thousand feet of the seafloor. These wells cannot be drilled with conventional equipment. Underbalanced or near balanced drilling which has been successfully used onshore may be the only method to drill such formations. The concentric riser would make it possible. The time and equipment required to test a deepwater well would be significantly reduced if a conventional surface type hook up could be used. However, few rigs will be able to run a concentric riser. The latest generation of drillships, such as the Discoverer Enterprise, will have the capability and equipment to do so. The paper will address the advantages, the operational procedures and hardware needed to utilize a concentric riser safely

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