bluuebunny/crossref_metadata_2025 huggingface dataset:
Rheological Responses to Variations in Aqueous-Based Zirconium Crosslinker Chemistry
Authors: Harry David N. , Moorhouse Ralph , Matthews Les , Chen Gong
Published: December 2007

Aqueous based zirconium crosslinked fracturing fluids have seen widespread service since the early 1980's. Today, zirconium crosslinkers are used with many types of polymer solutions, across a pH range of from less than 1 to greater than 12. at bottom-hole temperatures of from less than 100F to greater than 400F. There is no doubt among workers in the field that the same zirconium crosslinked fracturing fluid is not suitable for such a wide range of applications, and, yet, there has yet to be published a systematic evaluation of the impact first order changes in the composition of zirconium crosslinkers have on rheological performance. This study endeavors to provide such a systematic evaluation.

Aqueous-based zirconium crosslinked systems can be made with a wide range of functionality to meet specific performance needs. In hydraulic fracturing fluid systems utilizing zirconium crosslinked guar or guar derivatives, changes in the crosslinker due to differences in the zirconium raw material source, the ligand to metal ratio, cation type, and pH of the system cause significant differences in rheological performance. In particular, crosslink time, temperature and stability at temperature (for a given shear regime) can be controlled by manipulation of the aforementioned factors. This study presents a systematic evaluation of these factors and discusses how an understanding of their interrelationships is essential in predicting performance of a crosslinker or designing a new fluid system.
Zirconium Additive Improves Field Performance and Cost of Biopolymer Muds
Authors: Burrafato G. , Guameri A. , Lockhart T. P. , Nicora L.
Published: December 2007

Novel inhibited biopolymer muds are reported that provide both environmental compatibility and excellent performance in drilling reactive shales. These muds employ the new dispersing agent zirconium citrate (ZrC) which provides effective rheology control for the build-up of low density solids in the mud. Laboratory experiments on Xanthan gum and Scleroglucan biopolymer field muds demonstrate the exceptional thinning power of ZrC compared to other deflocculants. Results from the application of ZrC for rheology control in Scleroglucan-potassium muds are given for two wells drilled in southern Italy. In both wells, the use of ZrC strongly reduced the need for mud dilution, compared to previously drilled wells, and proved an effective means for stabilizing rheology during stopped circulation. On account of the sharply-reduced mud volumes required, use of ZrC reduced total fluid costs by 26 and 44% for these wells.
A Simple Method for Determination of Radius of Investigation for Non-Newtonian Fluids and Other Non-Ideal Systems
Authors: Wang Xinhai , Ma Shouxiang
Published: December 2007

Transient pressure testing is an important tool in obtaining reservoir information. Information derived from transient tests is useful only to those portions of the reservoir in which flow has occurred during the test. Thus, determination of radius of investigation (ROI) is essential. The most commonly used ROI equations were derived for Newtonian fluids Darcy flow in a homogeneous formation. Limited information of ROI is available for systems involved with non-Newtonian fluids or non-Darcy flow which could be important in polymer flooding or production of gas wells.

ROI was determined in this paper by combining material balance equation and pressure distribution at any given testing time. This method of determining ROI was applied to non-Newtonian power-law fluids Darcy flow and Newtonian fluids non-Darcy flow in both homogeneous and composite formations.

Main observations from this study included that for non-Newtonian power-law fluids:ROI was compared with a literature ROI model which is applicable in the range of 0<n<1. Within {0,1}, the two models give consistent results with the difference being zero at about n=0.6. The applicable range for the new model however is n 0 9.When n<1, ROI increases with flow rate, q, while n>1, ROI decreases with increase in q. At n=1, ROI is independent on q.Difference between original formation permeability, k, and the permeability around wellbore, kA, has a significant effect on ROI if kA/k<1.

The effect of kA /k on ROI increases with n, kA/k has minor effect on ROI if kA/k>1. For Newtonian fluids non-Darcy flow,ROI is dependent on flow rate,ROI is less than that for Darcy flow, andROI decreases with increase in turbulent factor.

Introduction

Radius of investigation (ROI) is used to estimate the time required to test the desired area in a formation. The most commonly used radius of investigation, ri, was obtained by van Poollen,1 ri,P, by assuming that a Newtonian fluid flows in a uniform, homogeneous, and isotropic formation under the conditions of Darcy flow. (This is referred as ideal systems.)

Equation 1

where k is the formation permeability, f porosity, µ Newtonian fluid viscosity, Ct total compressibility, t testing time, and E1 is a unit conversion factor. A detailed review and discussion of Eq. 1 was given by Johnson.2

Consistent units should be used in Eq. 1 and all the following equations in this study. However, direct application of these equations could be difficult. Therefore a unit conversion factor, E, is included for the more convenient field units. If the parameters in Eq. 1 have the units as shown in Table 1, E1 is equal to 0.016238.

Numerous pressure transient studies for non-Newtonian fluids3–6 and high flow rate non-Darcy flow7–9 have been reported. However, limited information on ROI was available for systems involved with (1) non-Newtonian fluids, (2) non-Darcy flow, and (3) non-homogeneous porous media.
Pre and Post Gravel Pack Pressure Transient Testing of Layered Reservoir Wells
Authors: Al-Haddad S. , Hebert J. , Arbaugh R. , McKnight D.
Published: December 2007

Permeability and skin factor can be misestimated from well testing data taken after completing wells in layered reservoirs. Results presented in this paper are based on field data and numerical simulation work on two wells in an offshore Louisiana field.

Testing results taken after completing the first well in the field with a gravel pack, gave considerably lower than expected permeability results that could have jeopardized the future development of the field. Well performance analysis based on pre-gravel pack flow, as well as investigation of existing well log data, indicated the possibility of a layer of higher permeability within the tested interval. In consideration of this analysis, a decision was made to proceed with the drilling of a second well in the field and perform a pre-gravel pack test to obtain original reservoir data. Then, the completion design for the second well and the treatment strategy for the first well would be based on the proposed pre-gravel pack test results of the second well.

The pre-completion impulse testing of the second well, drilled to the same reservoir, gave a higher calculated permeability than the first well, confirming our expectation. A new completion design was proposed and implemented on the second well. Post-completion transient testing indicated that the second well completion maintained communication with the higher permeability layer allowing the evaluation of the well completion skin. The new reservoir permeability then used in reservoir simulation resulted in a more reliable field production performance prediction and evaluation. Well log data, well test data, completion design, and reservoir simulation results are presented in this paper.
An Organized Approach Toward Remediation of Salt-Affected Soils at E & P Sites
Authors: Carty D. J. , Priebe W. F. , Swetish S. M. , Crawley W. W.
Published: December 2007

Strategy and tactics for remediation of salt-affected soils at exploration and production (E&P) sites continue to challenge the petroleum industry. Although substantial refinement of remediation technology is still required, an adequate database currently exists for the remediation of most sites. Permanent remediation (complete cure) requires correct measurement (examination), interpretation (diagnosis), and selection and application of the appropriate technology (prescription) for the specific physical, chemical, and cultural condition of each unique site (patient). Differences among spill circumstances include the volume and concentration of produced water spilled, the soil's texture, slope, stratification, erodibility, mineralogy, chemical characteristics, vegetation status, and drainage characteristics, as well as seasonal water table variation, site meteorological conditions, and corporate, regulatory, and landowner constraints. A decision-tree incorporating these and other variables will be presented in a forthcoming publication. Major factors of concern and emerging technologies are highlighted in this paper. Society of Petroleum Engineers, (SPE) members are invited to join in forming a national technical support network to provide a comprehensive and readily available database with which the petroleum industry can better examine, diagnose, prescribe, and cure salt-affected soil "patients."
Progressing Cavity (PC) Pump Design Optimization for Abrasive Applications
Authors: Delpassand Majid S.
Published: December 2007

The progressing cavity (PC) pump is well established as the pump of choice for handling abrasive solids. PC pump design can be optimized to achieve the best wear performance available for a given size. The wear optimization of the PC pumps is achieved through geometric design for minimum internal fluid velocities and by selecting proper materials of construction.

Wear causes PC pump failure by gradually reducing the volumetric efficiency and increasing pump slippage. This paper focuses on the parameters that influence pump wear, describes wear mechanisms, reviews design techniques for wear optimization, and presents field data to support some of the claims.
A Successful Water Shut Off. A Case Study from the Statfjord Field
Authors: Børeng Raymond , Svendsen Ove Birger
Published: December 2007

Gel is considered to have an interesting potential for water shut off applications, especially in fields having natural shale barriers and large permeability variations and/ or where reduction in tubing/ casing diameter is not wanted. This paper describes a case study from the Statfjord Field where polymer silicate gel was used to build up experience for water shut off applications of the lower producing interval in a well that produced from two intervals. The intervals where separated by 5m in 9 5/8" casing and located at approximately 3100 m.

The primary objective was to shut off water and secondly to evaluate gel technolog)'. Mechanical techniques and gel technology were considered as means of achieving the objectives. Both required the use of 2" coiled tubing in a live well (Fig. 14). Gel technolog)' was selected since diameter restriction in the casing was not wanted due to potential later perforations deeper into the well combined with desire of qualifying the technolog)' and related techniques.

This paper reports some of the results achieved in the laboratory, and give references to papers where the laboratory techniques and results are given, refs. 1 through 5. The pre planning and the laboratory' testing for finding a suitable gel formulation was also performed in collaboration with a service company.

Therefore this paper focuses mostly on the well performance, placement of plugs in the well by wireline and coiled tubing, pumping of the gel solution through the coiled tubing and into the lower perforation interval and evaluation of results.

The operation has been an economical success. After water isolation from the lower interv al, the well has produced oil with a gross value of 15 mill. U.S.$ in 6 months and the operation had a pay back time of 50 days.
Numerical Simulation of Steamflood Efficiency Improvement Through Use of Hydraulic Fracturing Technology
Authors: Manrique J. F. , Mukherjee H. , Mach J.
Published: December 2007

We present the use of fracturing technology to accelerate performance and improve ultimate recovery in heavy oil reservoirs. The applicability and efficiency of this approach were investigated by means of numerical simulation. A fully implicit 3-D thermal simulator was used to model the heat transfer efficiency and productivity enhancement when using this approach. Different scenarios were modeled for wells with horizontal and vertical fractures. This technology may be especially suitable for thinner reservoirs, dipping reservoirs and steam distillation drives.

The "heat plane source" concept is presented in this paper to explain the advantages of fractured steam injectors for improvement of thermal recovery processes. During steam injection, heat convection and gravity effects become dominant in the near wellbore area causing excessive heat losses and poor recovery. We suggest an approach that will minimize convection override of the oil while creating a more efficient and stable steam drive.

Numerical results suggest that production response of current steamflood operations can be improved by inclusion of hydraulic fractures. Additional advantages observed for fractured injectors suggested a modified injection schedule that improves productivity and steam allocation for neighboring projects. This results in a faster return of investment and substantial increase in cash flow during the early life of the project. The economic benefits were evaluated by incorporating the production response into an economic model that maximizes the Return of Investment and Net Present Value.
Evaluation of Particulate and Hydrocarbon Fracturing Fluid-Loss Additives Under Dynamic Conditions
Authors: McGowen James M. , Vitthal Sanjay
Published: December 2007

This paper presents the results of an industry consortium established to understand and allow modeling of the fluid-leakoff process in hydraulic-fracturing applications. Fluid-loss data was measured with a state-of-the-art experimental setup that included fluid preconditioning loops for high-shear and low-shear regimes and a novel cell design that minimizes flow irregularities. Previous papers 1,2 have presented the effects of experimental designs, shear rate, permeability, and pressure on the fluid loss of water-based systems with no fluid-loss control aids. This paper presents the results of experiments that used linear hydroxypropylguar (HPG) gel and HPG/borate fluid systems with various types of hydrocarbon and/or particulate fluid-loss additives in similar testing procedures.

This study has found that each fluid-loss additive has an optimum performance range that depends on the fluid type and core permeability. Hydrocarbon fluid-loss additives, even at low concentrations (0.5% by volume), were found to be effective in reducing the filter-cake permeability of crosslinked gel systems in low-permeability cores (less than 10 md). Unless effective particulate fluid-loss additives were also used, hydrocarbon additives were ineffective in reducing the spurt loss or the filter-cake permeability in higher-permeability cores. Since hydrocarbon additives principally work on reducing the filtercake permeability, they exhibited more shear-rate sensitivity than "neat" fluids. However, in contrast to the pressure-independent behavior of neat fluids, the fluid-loss coefficients with hydrocarbon additives increases with pressure.

Particulate fluid-loss additives were very effective in reducing spurt loss, especially for low-viscosity fluids. Inert and oil-soluble materials out-performed most water-soluble particu lates, particularly in higher-permeability formations. An investigation of the particulate particle size indicated that the optimum particulate size distribution must incorporate particles one to two times larger than the peak core pore size. Shear rate did not alter the particulates' effectiveness in controlling spurt loss; however, it did affect the filter-cake properties (Cw and vn values) in most situations similar to neat fluids. The addition of particulates did not change the compressibility of filter cakes that was observed earlier with neat fluids. The spurt loss with inert particulate additives was relatively independent of pressure, in contrast to the pressure-dependent spurt loss of neat fluids.
Understanding Proppant Closure Stress
Authors: Schubarth S. K. , Cobb S. L. , Jeffrey R. G.
Published: December 2007

The effect of closure stress on fracture conductivity has been well documented by laboratory measurement. Common industry practice for estimating closure stress on proppant in the field is to subtract flowing bottomhole pressure from the estimated in-situ stress of the pay interval fractured. This paper proposes that the closure stress on proppant in a fracture can be significantly higher than common estimations due to the influence of the bounding layers and the elastic response of the formation acting on the proppant. In this paper we will review past literature on fracture propagation, fracture conductivity and proppant placement and demonstrate the impact that increased proppant stress due to bounding layers can have on fracture conductivity and ultimately production.
Effects of Pressure Drop in Horizontal Wells and Optimum Well Length
Authors: Penmatcha V. R. , Arbabi S. , Aziz K.
Published: December 2007

As the length of a horizontal well is increased, its contact with the reservoir increases. But at the same time, the resistance to flow in the well also increases, which has a direct negative effect on the productivity of the well. The overall performance of a horizontal well depends on the balance of these two opposing factors. No reliable tools are currently available that account for both these factors in the evaluation of horizontal well performance. A semi-analytical well-model is developed which can quantify the effects of both single phase oil and two-phase oil/gas flow pressure loss in the well on the overall well performance. The model is quite flexible and can incorporate any friction factor correlation. A methodology is developed to show the effects of various reservoir, fluid and well parameters on well productivity. We demonstrate that ignoring frictional effects could lead to unrealistically higher production estimates and low breakthrough times for water or gas. As a result of pressure drop in the well, breakthroughs occur first at the heel of the well. A methodology is also developed to calculate the optimum horizontal well length.
Measured Rodstring/Tubing Wear and Associated Side Loading
Authors: Long Scott W. , Bennett Donald W.
Published: December 2007

Ever since the first installation of steel sucker rods in production tubing, the Petroleum Industry has been aware of rod string and tubing wear. The associated rod string and tubing wear with this artificial lift system continues to have an impact on the ability to economically produce oil and gas.

The downstroke phenomenon of sucker rod string compression, buckling, sucker rod/tubing contact and associated sucker rod/tubing wear is becoming more clearly defined (see References 1,2, and 3) throughout the petroleum industry.

This paper will provide the Petroleum Industry with a more accurate understanding of sucker rod and tubing wear resulting from sucker rod side loading initiated by downstroke sucker rod buckling. This paper will present a description of test equipment and test parameters resulting in the following: Calculated cycles to 100% tubing wall loss vs. side loading.Calculated cycles to 100% sucker rod diameter loss vs. side loading.Calculated cycles to 100% sinkerbar diameter loss vs. side loading.

A better understanding of sucker rod and tubing wear will provide the Industry with better sucker rod string design guidelines. Use of these guidelines can reduce costly sucker rod and tubing wear and failures that impact the ability of the Petroleum Industry to economically produce oil and gas.
The SpliTigatorTM: A Device for the Mitigation of Phase Splitting
Authors: Berger Eric L. , Kolthoff Karl W. , Schrodt James L.G. , Long S. Lynn , Pauley J. Craig
Published: December 2007

Phase splitting at piping junctions in two-phase steam distribution systems results in unequal steam delivery to injection wellheads and interferes with the optimization of injection rates. Texaco's researchers have investigated phase splitting and have devised and evaluated various methods for its mitigation. As a result of these efforts, the SpliTigatorTM, a device for the mitigation of phase splitting, was developed and patented.

The SpliTigator is designed to deliver a specific steam quality to the branch leg of a Tee junction. The SpliTigator delivers consistent steam quality as branch flow rate, system pressure, and inlet flow conditions change. SpliTigator pressure losses are small, allowing numerous devices to be used in series. The use of the SpliTigator has been extended to flow rate and steam quality measurement and other two-phase systems. This paper presents an explanation for phase splitting, discusses the theory behind the design and operation of a SpliTigator, and presents results from both laboratory testing and field applications.

Introduction

The phase splitting behavior which commonly occurs at piping junctions within two-phase piping systems results in unequal distribution of the phases between branches of the junction. In steam distribution systems, inequitable phase splitting results in the delivery of a wide range of steam qualities and mass flow rates to injector wellheads. The SpliTigator is an effective and inexpensive device for the mitigation of phase splitting that has been developed through the joint efforts of Texaco personnel at the Bakersfield Division's Kern River Business Unit and at the Exploration Production Technology Division's Steam Flow Research Facility. An isometric diagram of a SpliTigator is shown in Figure 1. The following summarizes the most significant features of the device.

The SpliTigator:–Controls branch steam quality within a few quality points of design over a wide range branch flow rates, system pressure, and trunk line steam quality.–Creates no additional pressure drop in the main line and requires very little pressure drop in the branch for effective operation.–Requires no moving parts, no periodic adjustments, and little or no maintenance throughout the life of the steam flood.–Is constructed from off-the-shelf piping components as a drop-in replacement for existing branch Tee junctions.

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Surface Facilities Management for Thermal Recovery Processes
Authors: Heiba Adel A. , Barua Santanu , Dutta-Roy Kunal
Published: December 2007

Following the delineation and development of a field, the recovery of oil by cyclic steam stimulation and other thermal methods is controlled by actions taken at the surface. A number of operational variables effect the optimal management of steam stimulation programs. Generally these variables relate to the generation and allocation of steam for injection at production wells. Because the number of variables can be large, the management of steam stimulation programs is seen to require that solutions be found to constrained multivariate optimization problems.

In this paper, a novel and integrated approach is presented to the optimal management of cyclic stimulation programs. The approach combines the use of technologies to simulate the flow of steam in networks and wellbores with an industrially tested variant of the Successive Quadratic Programming algorithm (SQP) for process optimization. Examples are presented that illustrate the ability of the integrated approach to optimize the allocation of steam in distribution systems for which (1) the objective is to minimize the loss of thermal energy in surface piping and wellbore tubing, and (2) the objective is to increase the value of oil production that follows stimulation. Extensions of the approach to more realistic allocation problems are found (i) to require the inclusion of steam generation costs in the formulation of optimization problems, and (ii) to require the incorporation of mechanistic reservoir models for the stimulation of oil production by steam injection.
Delivering Step Change in Performance from Well Construction Teams
Authors: Thorogood J. L.
Published: December 2007

The last five or six years have witnessed a revolution in well construction contracting practices. However, performance has continued to evolve incrementally instead of showing the step change that was predicted by those who advocated such a radical change. There are a number of factors that are likely to have contributed to this situation. The review presented here suggests that the major problem stems from a shortcoming in the way alliance teams are built. It is suggested that a single coherent structure which joins business process, performance measurement and organisational structure into the delivery of an end result will produce the desired step change in performance. Exceptional performance cannot be delivered through structure and process alone. Effective teams require inspired leaders who are capable of directing the team's energies towards challenging, yet achievable, targets.
Cost Effective Horizontal Drilling in the Troll Field Through use of State of the Art Technology and Optimal Operations
Authors: Henriksen N. , Storegjerde D.
Published: December 2007

Less than a decade ago, the thin oil zone of the Troll gas field was almost written off as uneconomical. Extraction of the oil required the drilling of long horizontal sections with high accuracy. This was proven feasible by a 500 m (1650 ft) long horizontal well in 1989 and a second 800 m (2625 ft) horizontal well in 1990. Based on these encouraging results, a development plan was made for a large scale subsea development with 800 m horizontal wells at a budgeted drilling cost of 80 million NOK (12 million USD) or 46 days per well. Today, the highly successful development is producing 250,000 bopd. Moreover, 2,000 m (6,500 ft) horizontal wells are being drilled routinely at a cost of 40 million NOK (6 million USD) or 25 days per well, i.e. half the budgeted cost. Also, planning of multi-lateral wells has started. This paper describes how the efficient use of technology and optimisation of drilling operations have made the significant cost reduction possible.
Pro-Star 2000: Investing in State-of-the-Art Drilling Technology in Order to Reduce the Overall Well Cost Without Compromising on Quality and HSE Issues
Authors: Boering E. , Swart D. , Young T. F.
Published: December 2007

A revolutionary change in the Operator-Contractor relationship through partnering, has created a stable environment for rig and work process improvement. The PT-2000 rig, which commenced operations in 1995, is one of the major results of this strategy.
Teamwork Results in a World Record Length 16 in. Casing String
Authors: Jellison M. J. , Eckroth J. J. , Fulton Jim , Ogren Larry , Moore P. W. , Barber Vance , Vesely Don
Published: December 2007

On 12 April 1996 Louisiana Land and Exploration Company successfully ran and cemented a 14,510 ft string of 16 in. 146.2 lbf/ft (0.907 in. wall) P-110 casing in their Big Horn 4-36 well located in Fremont County, Wyoming. The string had an air weight of over 2.1 million pounds and a hook load of over 1.8 million pounds. This world record feat was the result of a concerted, team effort involving Engineering, Purchasing, Suppliers and Service Companies. The 16 in. casing string played a critical role in drilling the well that had a planned total depth of over 24,000 ft. At the time this paper was written, the final section of the well below the 7-3/4" liner (set at 23,162 ft) was being drilled.

The paper details the complementary roles and contributions of each group involved in this challenging project. The overall well design philosophy is discussed along with a review of the detailed 16 in. casing design structural load and von Mises tri-axial stress analysis. The specialized casing material specifications and manufacturing procedures are presented and related to casing string performance requirements. The paper outlines the casing connector selection criteria and describes the premium connector used on the casing string to withstand the high axial forces and pressures encountered while running the casing and drilling the well. The equipment and procedures used to safely and efficiently run the casing string in a total of only 43 hours from rig up to tear down with 31 hours running time are also described.

The 14,510 ft casing string was cemented back to the surface in a single stage. The paper addresses the importance of the mud properties prior to cementing as well as the design and execution of the cement job. Both were critical to successfully completing the job.
Reciprocating Cement Slurries After Placement by Applying Pressure Pulses in the Annulus
Authors: Haberman J. P. , Wolhart S. L.
Published: December 2007

This is a report on progress to reciprocate or vibrate cement slurries deep in wells, after placement, with the objective to prevent gas migration and to improve cement bond logs. Pulses of relatively low pressure (circa 100 psi) compressed air or water were injected into the annulus at the surface (Figure 1).

This imparted motion to the cement particles in the slurry in two ways: A fast pressure pulse traveled through the slurry at the speed of sound andA slower reciprocating motion resulted from the compressibility of the fluid.

The results of full-scale tests in wells are reported and discussed below.
Slim Hole Exploration: One Year Experience in Romania
Authors: Groenevelt P. , Brown D. , Keenan T. , Calis H. , Kerbart Y. , Fanuel P. , Lamine E.
Published: December 2007

FORASLIM 1 is an integrated Drilling and Coring system dedicated to the construction of wells with small diameter to depths of 3500m. The objective is to provide a high cost reduction of exploration drilling in remote onshore areas with the following requirements: Environmental impact minimisationDrilling EfficiencyDrilling safety(No reduction in well control and safety standards)Complete Geological Evaluation

In order to reach these objectives a fit for purpose drilling system has been developed (ref. 1). The Slim Hole rig FORASLIM 1 has been commissioned in April 1994. The first drilling campaign was completed by ELF Gabon and is related in reference 2.

The present paper relates the experience acquired with Shell during the drilling of three wells in Romania under an integrated services contract managed by the drilling contractor Forasol. This experience concerns the drilling and coring processes, and the quality of the geological evaluation obtained.
Predicting Microporous Low-Permeability Facies using Sonic and Nuclear Porosity Log in a Middle-East Carbonate Reservoir, Berri, Saudi Arabia
Authors: AlShammery Matter J. , Frignet B. G.
Published: December 2007

The Berri Hadriya limestone is a mature oil reservoir which has been produced for more than two decades. No gas cap is present. The oil sweep is assisted by flank water injectors. The lack of a straightforward porosity-permeability relation has been observed from core analysis. Extensive thin-section studies have shown that the presence of microporosity was the root cause of low-permeability/high-porosity zones. Today, 27 cored wells have been analyzed and revealed the presence of microporosity zones which severely affect reservoir performance. Until recently, microporosity has not been detected by conventional log analysis, and required costly and time-consuming core analysis.

Intuitively, the sonic responds primarily to porosity variation and also to factors such as lithology, fluid and texture. Since Hadriya formation has uniform lithology, and fluid, it is ideal for understanding the sonic-log response relative to only porosity and textural variations.

Sonic logs have been run in all cored wells in the field, but failed to detect microporosity on their own. However, by comparing porosities derived from sonic, neutron, and density logs, it was noticed that in zones of microporosity the sonic-derived porosity was always the highest among the 3 readings. This observation was confirmed in all Hadriya cored wells. A simple algorithm was then designed to flag microporous facies by comparing all three logs. A 90% agreement was obtained between log-derived microporosity detection and core results. The technique was later applied to 11 uncored wells, and the microporosity was re-mapped across the field. The new map better matches an already established flood-front position, therefore boosting our confidence in our prediction methodology.

An explanation relating the Hadriya empirical observations to the framework of the Biot-Gassmann sonic theory is given here. It may encourage future use of sonic logs in studying more carbonate reservoirs worldwide.
Performance Review - In-Situ Combustion Project, West Casa Blanca Field, Duval County, Texas
Authors: Eskew James O.
Published: December 2007

The West Casa Blanca Field in-situ combustion project was initiated in February, 1967 with air injection into the Cole reservoir. The field, which is located near Freer, Texas, contained 16 pumping oil wells with an average production of 62 barrels of oil per day prior to ignition. Primary recovery from the 1,030' reservoir had been 1.1 million barrels of oil, or 28 percent of the original oil in place.

By the end of May, 1967 production had increased to 160 BOPD with air injection of 1,500 Mcf per day. A burn front was formed as evidenced by the appearance of carbon dioxide gases in the producing wells. Production continued to increase with the Production continued to increase with the drilling of an offset well to the air injector and peaked at 346 BOPD during December, 1967. In October, 1969 the project was expanded with the addition of a second air compressor and air injection well. December, 1971 production averaged 151 BOPD. There have been production averaged 151 BOPD. There have been 371,000 barrels of oil produced since project start-up and 4,500 MMcf of air have been injected into the reservoir. The burned volume is calculated to be approximately 400 acre-feet of the reservoir.

only minimum data has been taken during the past five years of the project: well tests, air injection volumes, and gas analysis. This historical data is presented in this paper.
Corrosion Problems in Below Grade Wellhead Equipment and Surface Casings
Authors: Farooqui M.A.S.Z. , Bitar G.E.
Published: December 2007

Inspection of the below grade well head equipment has shown corrosion damage to the buried landing base, casing spools and surface casing, especially in water injection and supply wells in onshore fields in Saudi Arabia. This paper describes the problem, examines possible reasons for the occurrence of corrosion and then discusses procedures and standards that have been developed to regularly inspect all wells, perform the required repair work in a safe and cost-effective manner and provide durable protection with field-applied corrosion resistant coating on all buried equipment.

Introduction

Occurrence of corrosion damage in the buried well head equipment and surface casing immediately below the landing base has been a concern in the onshore fields in Saudi Arabia. Initial random inspections of the below grade wellhead equipment in the mid-eighties showed corrosion damage to the buried landing base, casing spools and surface casing. The damage was occurring in spite of an apparently successful cathodic protection program that has reduced the number of casing leaks due to external corrosion damage.

The possible causes of the corrosion damage are: leakage of water from surface piping and wellhead valves during various operations on water related wells, presence of highly saline and corrosive water close to surface in "subkha" terrain, and, impediments to effective cathodic protection at shallow depths.

In view of the safety and environmental hazards associated with possible shallow leaks from corroded casing or failure of wellhead equipment, a number of steps have been taken to control the damage. These include regular inspection and repairs at regular intervals, protection with field-applied corrosion resistant coatings and a requirement to coat all new wells immediately after the rig release.

Regular inspection and protection of the below grade wellhead equipment has successfully reduced potential hazards associated with casing failures at shallow depths. Repair and renovation costs have been effectively reduced by establishing guidelines for safe acceptable thickness limits and by adopting rigless repair procedures.

Problem Description

Typical landing base and surface casing equipment for onshore wells is depicted in Figure-1. The 13-3/8" casing is either welded or screwed on to the 13-3/8"x13-5/8" landing base. The 18-5/8" conductor pipe is cemented at a distance ranging from a few inches to 2–3 feet below the landing base.

A typical landing base inspection operation involves excavating the cellar to below the landing base to expose three to six feet of the surface casing or until hard cement is encountered below the landing base, which ever is earlier. The exposed section is sand blasted and then inspected for evidence of corrosion. The data from such inspections for the last six years (1991 through 1996) is presented in Table-1, while Figures 2 through 4 illustrate some cases of severe corrosion damage on the landing base and surface casing on oil as well as water wells.

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Encapsulated Scale Inhibitor Treatment
Authors: Al-Thuwaini J.S. , Burr B.J.
Published: December 2007

Scale formation and deposition (CaCO3) in production facilities is a problem encountered in the Ghawar Field in Saudi Arabia. The scale deposition causes production loss and safety hazards. Downhole scale inhibitor squeeze treatments have proven successful in controlling this scale accumulation. However, weak producers (low oil rate and high water cut wells) could not be squeezed due to the difficulty anticipated in re-starting production from these wells because of the high volume of water normally needed to squeeze the inhibitor into the formation. Starting in 1994, an alternative method (the encapsulated inhibitor treatment) was tried for selected weak wells.

This paper presents the design of the encapsulated inhibitor treatment, treatment procedure, a field case history with scale inspection results, economical analysis of this treatment versus the regular downhole treatment and the future plans. To-date, more than ten treatments have been performed in Saudi Arabia. Regular visual inspection of selected wells revealed no scale accumulation up to 24 months after the treatment. Current plans are to treat more wells for further evaluation.

Introduction

Calcium carbonate CaCO3 scale is the most common scale encountered in the Ghawar field production wells. Its deposition in surface and subsurface equipment causes loss in oil production and major operational problems. The scale control program was started in the Ghawar Field in 1986, and since then, conventional scale inhibitor squeeze treatments have been successful in controlling scale accumulations. Saudi Aramco field experience has shown that weak oil producers, especially high water cut wells (WC >70%), when treated using a conventional scale inhibitor squeeze, require several reviving attempts before the wells can be put back on production and in some cases the wells might remain dead. This is mainly due to the hydrostatic head created by the large treatment fluid volumes normally pumped during a conventional treatment where the inhibitor is squeezed into the formation to a predetermined radius.

In 1994, a new scale inhibitor treatment "Encapsulated Inhibitor Treatment" was introduced to Saudi Aramco. The main advantage of this treatment is the placement of the treatment fluids in the rathole rather than squeezing it into the formation. Therefore, the encapsulated scale inhibitor treatment is suitable for the weak wet oil producers with high water cut. To-date, more than ten wells in the Ghawar Field and an offshore field have been treated with the encapsulated inhibitor, without any difficulty in bringing the wells back on production. Some of these wells are being closely monitored for rescaling by performing regular visual inspections. To date none of these treated wells have shown scale redeposition after up to two years following the treatment of the first well.

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Drilling Contracts and Alliances: The Pendulum Swings
Authors: Gooch Stephen G.
Published: December 2007

As the attached graphs (Figures 1, 2, and 3) illustrate, utilization of offshore rigs has increased to levels not seen since the early 1980's creating supply shortages in many markets. This tight market condition is expected to continue for some time as demand is not anticipated to abate and the supply will be relatively static. While rates are approaching levels high enough to encourage new builds, as yet a spate of new construction has not ensued. Even if new construction occurs, it will take another two or three years for deliveiy of these new rigs. How has and will this tight market condition affect drilling contracts and alliances?

DRILLING CONTRACTS

In general, operators have used a favorable supply/demand rig ratio during the past 15 years to reshape drilling contracts in their favor. The current tight market has reversed this trend, at least in part, and is expected to continue to do so. The purpose of this presentation is not to seek out perceived inequities in drilling contracts, but to focus on certain issues which will be impacted by the tight market. The following is a discussion of some of these issues.

Extension Options

I have chosen to address the issue of extension options first since options have become a major impediment in predicting rig availability and securing future jobs both for the drilling contractors and rig-seeking operators.
Drill Fast, Safe and Friendly with Incentive Contracts
Authors: Reiley Richard H.
Published: December 2007

Abu Dhabi Company for Onshore Oil Operations (ADCO) recently initialed an incentive contract to encourage drilling wells quicker, safer and in an environmentally friendly manner, Not content just to drill fast, safe and friendly, the Drilling Division made the incentive award contingent upon delivery of high quality wells free of defects. This paper describes the structure and implementation of effective incentive contracts.
Drilling Fluids for Short Radius Horizontal Wells
Authors: Ezzat A. M. , Esmail O. J. , AI-Ammari S. M.
Published: December 2007

Several old wells have been successfully sidetracked and short radius horizontal holes were placed at the top of the Arab-D reservoir. The main objectives of this type of recompletion are to reduce water coning and improve the oil recovery at the water flood front. Several attempts were made to sidetrack the first well. The downhole motor failed to build the hole angle at the required buildup rate while penetrating the anhydrite formation between the base of Arab-C and the Arab-D. Hole enlargement across the anhydrite section was found to be the reason for the tool failure.

Laboratory studies were carried out on anhydrite core samples taken from the base of the Arab-C section. Examination of the core samples by XRD provided detailed mineralogical composition of the rock. To determine the dissolution and erosion effect of different fluids, core plugs were hot rolled in stainless steel cages placed in steel aging cells filled with the drilling fuild samples. NaCl brine-based fluids dissolved up to 3 wt% of the rock sample and eroded additional 7 wt%. CaCl2 brine system treated with Ca(OH)2 and CaSO4.2H2O showed no dissolution and very little erosion. Oil-based invert emulsion mud with CaCl2 brine as the internal phase showed absolutely no effect on the rock samples.

A non-damaging oil-based mud formulation was developed and successfully used to sidetrack and drill several short radius wells. This paper presents the laboratory data along with the drilling and completion fluids formulations being used. Problems that were encountered during the drilling of the first well are also discussed.
Biodegradation of Synthetic Muds : Oxidative Pretreatments
Authors: Rabion A. , Perié F. , Bassères A. , Guillerme M. , Zurdo C.
Published: December 2007

This report describes a simple pretreatment to enhance olefin-based pseudo-oil-based mud biodegradation under bottom of the sea conditions. The suggested treatment involves the oxidation of cuttings with diluted nitric acid prior to liquid-solid separation, sea-water neutralization of the mud, and biodegradation. Saturated hydrocarbons such as polyalphaolefins contained in cuttings were not degraded under the proposed reaction conditions. Comparison of oxidized and untreated olefms-impregnated cuttings clearly demonstrates that oxidized cuttings biodegrade more rapidly than untreated ones. Furthermore, we demonstrate that oxidized cuttings allowed for an enhanced evolvement of carbon dioxide as compared to unsoiled sediments. In addition it was shown that olefins have an inhibitory effect upon the sediment mineralization -and that overal CO2 evolvement is significantly lower with untreated cuttings soiled sediments as compared to the unsoiled sediments.
An Evaluation of the Radiation Health Physics Data Collected at a Commercial NORM Oilfield Waste Disposal Facility With Application to Field Production Facilities
Authors: Lyon F. L. , Hebert M. B. , Marinello S. A.
Published: December 2007

Regulations pertaining to naturally occurring radioactive materials (NORM) in oilfield wastes have now been promulgated in many of the major oil & gas producing states (AR, AL, LA, MS, NM, TX, etc ). This paper will evaluate the radiation exposure of workers and members of the general public to these wastes by looking at the radiation health physics data compiled at the largest NORM oilfield waste disposal facility in the country. This facility, owned by Newpark Environmental Services, has been in operation since October, 1994 In this paper, we will assume that the facility (operating under a typical worker protection plan) represents a worst case scenario for exposure to radiation when compared to oil & gas production facilities containing diffuse NORM.

Monitoring methods used to determine both external and internal exposure will be described for both occupational doses (not to exceed 5000, millirem (mrem) per year) and doses to individual members of the public (not to exceed 100 mrem per year). Occupational monitoring included measurements of external dose using individual thermoluminescent dosimeters (TLDs), breathing zone air samples (BZA) to determine the potential intake to workers in conjunction with derived air concentration (DAC) limits, and urine bioassay samples to determine actual individual intakes in conjunction with annual limits of intake (ALI). Public monitoring included continuous external gamma monitoring using environmental TLDs at multiple locations around the facility, downwind boundary effluent air monitoring and passive radon monitoring. From these measurements, a total effective dose equivalent (TEDE) can be calculated and compared to the limits for occupational and public exposure.

Though the data were analyzed over time in the paper, they can be summarized, since the opening of the facility through September 30, 1996 (24 months), as follows: The average annual TEDE for occupational dose is <5 mrem/year.The same calculation for public exposure is <25 mrem/year. The public dose is higher because 100% occupancy must be assumed, whereas workers exposure is based on actual time on the job.

Through the end of 1996 (27 months), 129,999 barrels of NORM oilfield wastes were received with an average specific activity of 131 picoCuries per gram (pCi/g) for 226Ra and 708 pCi/g total activity (the range was 3-5,865 pCi/g 226Ra and 15-28,509 pCi/g total activity).