bluuebunny/crossref_metadata_2025 huggingface dataset:
Miscible Drive Field Applications in the Block 31 Field
Authors: Kern L.R. , Kimbler O.K. , Wilson R.
Published: December 2007

Introduction

Pressure maintenance by gas injection has been in operation for the past eight years in the Devonian formation of the University Block 31 field. The object of this operation is to achieve miscible displacement of the oil and consequently increase the ultimate field recovery. It is estimated that miscible high pressure gas displacement will yield three times as much recovery as by natural depletion (solution gas drive) mechanism.

Earlier papers have dealt with the mechanics of miscible displacement and a description of this operation. We will not attempt to expand upon this subject further here, but merely state that by laboratory experiment it has been found that in order to achieve miscibility between injected gas and this Devonian reservoir fluid, it is necessary to maintain 3,500 psi pressure at the displacing gas front. Although the average reservoir pressure has declined below 3,500 psi, the injection pressure has been sufficiently high to maintain at least 4,000 psi pressure at the gas front in all injection wells.

After two years of injecting gas into the G–2 well it was noted that this area was not increasing in pressure as expected. It was suspected that injected gas was leaking to other formations because there was less repressuring than predicted by material balance. This paper deals with one approach to the problem of gas losses and the corrective and control measures involved.

Reservoir Description and Injection Operation

The Block 31 Devonian field covers about 7,000 acres. The Devonian formation is on an anticlinal structure at a depth of 7,900-ft subsurface at the crest. The gross thickness is 1,000 ft. The field boundary is defined by water closure at 9,000-ft subsurface. The main producing section is located 450 to 800 ft below the top of the structure. This interval contains 85 per cent of the total in-place oil.

Seventy-three wells are presently completed in the Devonian on about an 80-acre spacing. Fifteen of these wells are currently being used for gas injection, basically in nine-spot injection patterns.
Mixed Finite Element Method for Miscible Displacement Problems in Porous Media
Authors: Darlow B. L. , Ewing R. E. , Wheeler M. F.
Published: December 2007

Effective numerical simulation of many EOR problems requires very accurate approximation of the Darcy velocities of the respective fluids. In this paper we describe a new method for the accurate determination of the Darcy velocity of the total fluid in the miscible displacement of one incompressible fluid by another in a porous medium. The new mixed finite-element procedure solves for both the pressure and velocity of the total fluid simultaneously as a system of first-order partial differential equations. By solving for u = (− k/μ) ∇p as one term, we minimize the difficulties occurring in standard methods caused by differentiation or differencing of p and multiplication by rough coefficients k/μ.

By using mixed finite elements for the pressure equation coupled in a sequential method with a finite element procedure for the concentration of the invading fluid, we are able to treat a variety of problems with variable permeabilities, different mobility ratios, and a fairly general location of injection and production wells. Mixed finite-element methods also produce minimal grid-orientation effect. Computational results on a variety of two-dimensional (2D) problems are presented.
Improvements in Simulation of Naturally Fractured Reservoirs
Authors: Gilman James R. , Kazemi Hossein
Published: December 2007

Simulation of multiphase flow in heterogeneous two-porosity reservoirs such as naturally fractured systems is a difficult problem. In the last several years much progress has been made in this area. This paper focuses on the practical aspects of that technology. It describes a stable, flexible, fully implicit, finite-difference simulator in heterogeneous, two-porosity reservoirs. Flow rates and wellbore pressures are solved simultaneously along with fracture and matrix fluid saturations and pressures at all grid points. Hydrodynamic pressure gradient is maintained at formation perforations in the wellbore. The simulator is accurate enough to match analytical solutions to single-phase problems. The equations have been extended to include polymer flooding and tracer transport with nine-point connection for determining severe local channeling and directional tendencies. It is shown that the two-porosity model presented in this paper will produce essentially the same answers as the common single-porosity model of a highly heterogeneous system but with a substantial reduction of computing time. In addition, this paper describes in detail several two-porosity parameters not fully discussed in previous publications.
Shear Failure of Rock Under Compression
Authors: Maurer William C.
Published: December 2007

Introduction

It is difficult to produce tensile stresses under the high compressive stresses present in the earth; therefore, in deep drilling and geological faulting, shear failure predominates. This shear failure mechanism is complicated because rock is a heterogeneous material containing pore spaces, microfractures, elastic discontinuities and other imperfections. A study of shear failure of rock under pressure has been made to obtain a better understanding of this complex mechanism. A machine has been developed and used to measure the shear strength of rock and friction along sheared surfaces. This machine has certain advantages over the compression test-shear properties can be measured under low normal stresses and shear stress and normal stress can be varied independently. The first part of this paper is a description of shear failure of rock under pressure. The role of shear strength and friction along fracture surfaces in the shear failure mechanism will be discussed. The second part consists of a description of the shear machine and a discussion of the shear strength and friction data obtained using this machine. It will be shown that shear strength depends upon the size of the stressed zone, and that friction does not increase linearly with contact pressure as usually assumed. Attempts are made to relate some of the new concepts to tectonic failure and to drilling.

SHEAR FAILURE IN ROCK TRIAXIAL TESTS

The shear failure mechanism is illustrated by the triaxial test shown in Fig. 1. In this test, a cylindrical rock specimen is subjected to a confining pressure, pc, and an axial pressure, pa. These external pressures produce normal o and shear r stresses on inclined planes within the specimen equal to

(1)

(2)

where theta is the angle between the specimen axis and a normal to the inclined plane. Fig. 2 shows how triaxial specimens deform as the axial pressure is increased.

SPEJ

P. 167ˆ
A Thermodynamic Model of Redissolution of Calcium Sulfonate Precipitates in NaCl Solutions
Authors: Somasundaran Ponisseril , Ananthapadmanabhan Kavssery P. , Celik Mehmet S. , Manev Emil D.
Published: December 2007

Precipitation phenomenon in the sodium dodecylsulfonate system has been investigated in this study at various levels of CaCl2 in a wide range of NaCl concentrations. While precipitation is found to be caused by the formation of calcium disulfonate, redissolution of the precipitate at high sulfonate levels is found to occur only when micelles are formed. Correlation of the effect of ionic strength on the redissolution with that of it on micellization supports the proposed mechanism of micellar redissolution. A thermodynamic model capable of predicting the nature and concentrations of various species in solutions has been developed. The model was tested against different sets of experimental data and was found to predict the system behavior satisfactorily.
Laboratory Investigations of the Dynamic Stability of Polymer Slugs
Authors: Dietzel Hans Joachim , Pusch Günter
Published: December 2007

To assess the dynamic stability of polymer slugs, flooding experiments have been performed in sandpacks and consolidated sandstone cores. The investigations have been carried out with a hydroxyethylcellulose (HEC) and a biopolysaccharide (BPS) (scleroglucane). Highly saline water (100 g/dm3 [0.2 lbm/L]) was used for the displacement tests, as well as for the preparation of the polymer solutions.

From the eluate sampled during each flooding test, a concentration profile and a viscosity profile were recorded. A comparison between the two profiles gives an indication of the fraction of the polymer substance in the injected solution that does not contribute to the viscosity. From the recorded profiles, the influences of dispersion, adsorption/retention, and viscous fingering were established separately and quantitatively determined by means of material balances.
A High-Pyruvate Xanthan for EOR
Authors: Philips J. C. , Miller J. W. , Wernau W. C. , Tate B. E. , Auerbach M. H.
Published: December 2007

High-pyruvate xanthan (HP xanthan) is produced by a proprietary strain of the Xanthomonas campestris organism and is available in the form of a 3 to 5 % broth or a 12 to 15% concentrate. The liquid product is supplied commercially (FLOCON 4800 or 4800C™ from Pfizer Inc.) for use as a mobility control and permeability reduction agent for micellar, water-thickened, and waterflood diversion projects. This paper deals with use of the product for mobility control. The biopolymer is similar in structure to other commercial xanthans but contains a significantly higher level of ketal-bound pyruvic acid. Assay methods, including those applicable to field waters, are discussed.

While dilute HP xanthan exhibits viscosity/concentration profiles and pH sensitivities that are similar to other xanthans, it has superior tolerance to high levels of salinity and hardness. Injectivity, as measured by Millipore™ filtration, is not adversely affected by high levels of monovalent cations and magnesium ion. The presence of ferric ion produces severe filterability deterioration, while problems with calcium and ferrous ions are less serious. Good filterability in the presence of iron or hardness cations is restored by use of certain chelating agents and surfactants. Sequential filtrations of HP xanthan and other xanthans have been carried out with various-size Millipore membranes. On this basis, the effective size of the HP-xanthan molecule was shown to be no larger than 0.2 µm.

Compatibilities of HP xanthan with biocides, oxygen scavengers, and surfactants are discussed, as is information demonstrating control of microbiological problems and field propagation of the biopolymer.
Development of the In-Situ Combustion Process on an Industrial Scale at Videle Field, Rumania
Authors: Turta Alexandra T. , Pantazi Ion G.
Published: December 2007

The Sarmatian 3 Videle field is among the largest heavy-oil reservoirs currently known in the world. The oil viscosity under reservoir conditions ranges from 30 to 120 cp [30 to 120 mPa·s]. There are three producing horizons: Sarmatian 3a and 3b, partially overlying Sarmatian 3c.

The field was discovered in 1959. During 1964-76, a water-injection project was gradually expanded to the whole reservoir area. The average oil recovery at the present time is about 13%, and the producing wells are approaching the economic limit—the producing oil/water ratio is higher than 25. For this reason, it was decided to study the feasibility of producing the field by in-situ combustion to recover additional tertiary oil.

To obtain the necessary data, three field combustion pilots located upstructure in various areas of the reservoir are being operated. The performance of the three tests is presented and discussed. The favorable results obtained so far justify the full-scale application of the in-situ combustion process. A linedrive scheme has been selected so that a more or less continuous combustion front will move downdip. To supply the necessary air for a combustion front of more than 11.2 miles [18 km] in length, a giant compression capacity of about 247.2 × 106 scf/D [7 × 106 std m3/d] will be required.
Flooding of Gas Cap in Norfolk Garr Sand Unit
Authors: Nelson H.A.
Published: December 2007

The West Norfolk Garr Sand Unit, which contains a large gas cap, is being successfully flooded using a conventional five-spot pattern and filling the gas cap with water to prevent loss of oil by migration into the gas cap.

Pilot water injection was commenced in July, 1953, utilizing two 10-acre, five-spot patterns. Increased oil production was first obtained in Oct., 1954, and gas-cap injection began in Feb., 1955. Over 4.5 million bbl of water have been injected into the gas cap to achieve fill-up. It is concluded that the gas cap of reservoirs with shallow dips may be filled with water to prevent loss of oil into the cap by migration with no adverse effects on the oil-bearing portion of the reservoir.

Introduction

Water flooding the Pennsylvanian sands in Oklahoma is becoming increasingly important. Numerous fields drilled during the late 1940's and early 1950's are now reaching their economic limit, and the successful water flooding of some of these fields is stimulating considerable interest. Gas caps have created difficult problems in many of these fields. The successful flood of the West Norfolk field has led to the development of additional similar projects.

Ten years ago water flooding of the shaly sands, such as the Peru, was believed to be impracticable. However, more accurate engineering and geological techniques, combined with improved operating techniques, have led to the successful flooding of fields similar to the West Norfolk field.

Primary Development and Production History

Primary reserves in the West Norfolk field have been developed during two periods:from 1927 to 1930 andfrom mid–1949 to 1952.

In Oct., 1927, gas was discovered in the Peru sand (now known as the Garr sand) on the east side of the field and 10 gas wells were soon drilled along this eastern edge. Continued production from these wells resulted in some going to oil, and after turning to oil the wells produced from 5 to 10 BOPD. In mid–1949 the discovery well was completed in the oil sand. This well, now Unit Well 16, produced 60 BOPD after a 60-qt shot. Further development resulted in the drilling of 60 oil wells.

Primary production from 870 acres totaled 870,000 bbl from mid–1949 to July 1, 1953, when the field was unitized for water flooding. It is estimated that of this 870 acres the oil column encompassed 645 acres, while the gas cap encompassed 225 acres. Total primary recovery was estimated at 1,097,000 bbl.
Successful Strawn Sand Water Flood
Authors: Riley E.A.
Published: December 2007

The field performance of waterflood operations in the Cherrykirk field, located in North Texas, is proving highly responsive to water flooding. High injection rates, in the order of 0.95 to 1.00 B/D/acre-ft, are being utilized to make the project successful and economically feasible. Prior to any attempts at water flooding, a detailed reservoir study aided materially towards successful operations. Pilot injection was initiated Oct. 18, 1955, using a 20-acre double five-spot. The pilot flood indicated efficient water flooding could be conducted so the injection pattern was expanded on a five-spot plan to encompass full field operations. Oil recovery by primary methods to Sept. 1, 1955, was 804,545 bbl. Reservoir pressure was depleted rapidly within 21/2 years from an initial pressure of 558 psig.

A total of 2,901,575 bbl of water had been injected to Dec. 1, 1957, resulting in the recovery of 612,147 bbl of oil or 4.7 bbl of water injected per barrel of oil produced. The revenue to Oct. 1, 1957, from the T. H. Cherryhomes and the Newmont Oil Co. leases amounted to $953,336 from an investment of $164,722 development and equipment costs and $206,277 operating costs. This is $582,387 profit to the full working interest. Since the pilot development cost was $43,131 this is a risk to gain ratio of 13.5 to 1 or an expenditure to return ratio of 1 to 3.88. A high rate of income is still being realized.

Introduction

The Cherrykirk (Strawn) field is located approximately 10 miles east of Jacksboro in Jack County, Tex. (Fig. 1).The discovery well, T.H. Cherryhomes No.1, drilled in Dec., 1951, potentialed 90 BOPD pumping. All wells in the field were drilled by mid-year 1952. The highest initial potential, 112 BOPD pumping, was obtained from the Cherryhomes No. 12. Forty-eight other wells were completed in the field by 1952 (see Fig. 2). Some wells required frac jobs for completion as producers. Rotary drilling tools were used to drill the wells to the top of the pay. Casing was then run, cemented, and the wells "tailed in" with the cable tools. The program on the wells consisted of 90 to 100 ft of 10.75-in. OD surface casing and either 5.5- or 7-in. OD casing as a production string cemented with 100 to 125 sacks of cement.
Effect of Preheating on Kern River Field Steam Drive
Authors: Restine Joe L.
Published: December 2007

The productive formation in the Kern River field is a sequence of sands designated as the Kern River series. These fine to very coarse sands, each averaging 60 ft (18.3 m) in thickness, are separated by silt and clay interbeds. They are steam-displaced sequentially from the bottom up, one zone at a time.

Since steam drive became a viable recovery technique in the early 1960's, all Kern River field steamdrive design and planning was based on the use of a reservoir temperature of 85 to 90°F (29 to 32°C). It was recognized that zones immediately above a previously displaced interval eventually will become heated by the zone below through heat conduction. To a lesser degree, this also occurs in zones below the active drive.

With sufficient preheating, very thin sands, previously calculated to be uneconomical and scheduled to be deferred in favor of thicker sands, have proved very productive. The preheating of thicker sands also has resulted in significantly higher production rates than the non heated equivalent sands.

This paper discusses the numerical modeling work completed to evaluate the effects of preheating. Field results, including temperature surveys and production data, also are presented to substantiate the theoretical work and prove that preheating effects are an important consideration in a steamdrive operation.

Introduction

The Kern River field is a large, shallow, heavy-oil deposit located 5 miles (8 km) northeast of Bakersfield, CA. The reservoir is a sequence of up to seven sands designated as the Kern River series. These sands are separated by silt and clay interbeds. Both reservoir and fluid characteristics are very favorable for steamflood methods. The unconsolidated sands have high permeabilities of 1 to 5 darcies and porosities of 28 to 33 %. The average oil viscosity and reservoir temperature are 4,000 cp (4 Pa · s) and 85°F (29°C).
Three-Dimensional Hydraulic Fracture Propagation in the Presence of Stress Variations
Authors: Palmer Ian D. , Carroll H. B.
Published: December 2007

Models of three-dimensional (3D) fracture propagation are being developed to study the effect of variations of stress and rock properties on fracture height and bottomhole pressure (BHP). Initially a blanket sand bounded by zones of higher minimum in-situ stress is considered, with stresses symmetrical about both the pay-zone axis and the wellbore. An elliptical fracture perimeter is assumed. Fluid flows are one-dimensional (ID) Newtonian in the direction of the pay zone. Two models, FL1 and FL2, are developed. In FL1, a discontinuous stress variation is approximated by ar variation in the vertical coordinate, and the fracture criterion, Ki =Ke, is satisfied at both major and minor axes. The net pressure at the tip, Lf, of the long axis required by the boundary condition Ki =Kc does not seem crucial in determining fracture height or BHP (compare with one group of published models8,9 that assumes p = 0 at Lf). Model FL2 properly represents the discontinuous stresses, and satisfies Ki=Ke. at the wellbore but not at the tip of the long axis. A parametric study is made, with both models, of the comparative effects of stress contrast, σ2-σ1, Ke, pay-zone height, h, and Young's modulus, E, on fracture height and BHP. Results indicate that Kc does not have as much effect as either for σ2- σ1, at least for large stress contrasts. Model FL2 suggests the possibility of a rapid growth in fracture height as σ2−σ1 is reduced. Such modeling may be able to give an upper or "safe" limit on the pumping parameters (q and μ) to ensure good containment. When the stress contrast is high, σ2−σ1, ≥700 psi [4826 kPa], an analytic derivation of BHP appears to be a good approximation for the parameters we use, if everywhere the fracture height is assumed equal to the pay zone height. Although leakoff is neglected here, subsequent modeling results show that, for leakoff coefficients C≲0.001 ft-min−½ [3.9×10−5 m·s−½], the results herein are a good approximation to the case when leakoff is included.
Principles for Fracture Design Based on Pressure Analysis
Authors: Nolte K. G.
Published: December 2007

This paper reviews the procedures for interpreting, modeling, and predicting fracturing pressure. This review shows that excessive pressure resulting from fluid flow in the fracture can cause such problems as excessive height growth and screenouts, which reduce the potential fracture penetration. As a result, an important design consideration is to limit the pressure by controlling the fluid viscosity.
Optimization of Stiffening Rings' Position in Welded Tubular X-Joint
Authors: Salama Mamdouh M.
Published: December 2007

Experimental results are presented to show that the position of the stiffening rings in welded tubular X-joints has a great impact on the value of the stress concentration factor (SCF) at the hot spot as well as its location. Preliminary guidelines for an optimal ring position are proposed. proposed. Introduction

In offshore structures, such as semisubmersible drilling vessels and fixed platforms, tubular members comprise the main load-carrying components. The platforms, tubular members comprise the main load-carrying components. The design of joints between these tubular members is complicated because the radial flexibility of the tube walls leads to significant stress concentrations. Since many of these structures are subjected to alternating loads, the presence of stress concentrations can lead to an early fatigue failure. Ring stiffeners often are used as a means of reducing the SCF and thus increasing the fatigue life. This has been confirmed by the results of Maeda et al. and Matoba et al. The effect of the position of ring stiffeners on the maximum SCF value and, hence, the fatigue life is, to my knowledge, not available in the open literature. This paper represents a preliminary study of the effect of positioning of both internal and external ring stiffeners on the value and positioning of both internal and external ring stiffeners on the value and the location of the maximum SCF. It should be recognized that this paper is not intended to give a generalized recommendation for the optimal ring position but rather to alert designers and fabricators to the danger of position but rather to alert designers and fabricators to the danger of unoptimized position. Poor positioning of the rings can result in very little improvement in the state of stress as well as the expense and drawbacks associated with welding.

Experimental Details

The experiments were conducted on welded tubular X-joints with an angle of intersection equal to 900 (this joint also is classified as double-T joint).

JPT

p. 328
Evaluation of Fracturing Fluid Stability by Using a Heated, Pressurized Flow Loop
Authors: Lescarboura Jaime A. , Sifferman Thomas R. , Wahl Harry A.
Published: December 2007

A flow loop was used to evaluate the stability of fracturing fluids at high temperatures. The design provides enough pressure to prevent vaporization of water-base systems up to 350°F [177°C]. Crosslinked polymer systems from four service companies were evaluated at 180 and 245°F [82 and 118°C]. The tests showed that crosslinked fracturing fluids degrade with temperature and shear, losing much of their viscosity and proppant-carrying capacity in a few hours. Thermal stability is a major factor in selecting gels for fracturing deep, high-temperature reservoirs.
A New Approach to Shale Management in Field-Scale Models
Authors: Haldorsen Helge H. , Lake Larry W.
Published: December 2007

Virtually every sandstone reservoir contains significant amounts of shale. Although the sand/shale sequence in the wells may be known, a reliable reservoir description must define quantitatively the lateral continuity of the shale, the shale distribution in unsampled areas, and the effects of the shales on transport properties.

This paper presents statistical techniques by which the lateral continuity and spatial disposition of shales can be estimated. These techniques rely on shale statistics from the wells and outcrop statistics from appropriate depositional environments. The resulting shale description can be conditioned to conform with the observations of the wells.

The subsequent discretizing of the reservoir into gridblocks for numerical simulation yields large elemental units that usually contain both sand and shale. The paper concludes by showing how the permeability and porosity may be estimated from the disposition of shales within each block.
Prediction of In-Situ Combustion Process Variables by Use of TGA/DSC Techniques and the Effect of Sand-Grain Specific Surface Area on the Process
Authors: Vossoughi Shapour , Bartlett Gordon W. , Willhite G. Paul
Published: December 2007

This paper describes a new technique to predict the parameters that govern the performance of the in-situ combustion process. This prediction is accomplished by thermogravimetric analysis (TGA) and differential scanning calorimetry (DSC) of the crude-oil combustion. The effect of surface area on the in-situ combustion-tube runs was also investigated.

The crude oil studied was from Iola field, Allen County, KS. This oil has a gravity of 19.8°API [0.94 g/cm3] and a viscosity of 222 cp [0.222 Pa·s] at 100.4°F [38°C] and 98 cp [0.098 Pas] at 129.2°F [54°C].

At a bulk density of the combustion-tube pack of 104.26 lbm/cu ft [1.67 g/cm3], the minimum crude-oil content to support an adiabatic combustion process was estimated to be 7.1 wt%. This translates into 34.4% oil saturation for the sandpack of 37% porosity and the crude-oil gravity of 19.8°API [0.94 g/cm3]. However, the combustion front, in a sandpack of 70 mesh (specific surface area of 76 cm2/g [7.6 m2/kg]) with an oil content even greater than the required minimum oil content predicted by the present approach, did not sustain itself. Additional tube runs were performed with finer sand grains having specific surface areas of 317, 1,120 and 3,332 cm2/g [31.7, 112, and 333.2 m2/kg]. A strong, sustained combustion front was observed only in the last run—i.e., the greatest specific surface area.

TGA was applied to the samples taken at 1- to 2-in. [2.54- to 5.08-cm] intervals ahead of the front to study crude-oil distribution. In the case of unsuccessful runs, the amount of the crude oil ahead of the front decreased to a level that sufficient fuel could not be laid down to sustain the front. In the self-sustained run with the greatest surface area, crude-oil content immediately ahead of the front was even higher than the original sand/oil mixture. Therefore, a minimum surface area is required to provide conditions for sufficient fuel to be laid down by the coking process.

This finding is believed to be important in revealing the mechanism responsible for the lack of self-sustained combustion in sandpacks or porous rocks with low specific surface area. It also reveals the importance of the specific surface area available to the crude oil for determining whether a self-sustained combustion could be achieved.
Primary Cementing by Reverse Circulation Solves Critical Problem in the North Hassi-Messaoud Field, Algeria
Authors: Marquairi R. , Brisac J.
Published: December 2007

After usual cementing techniques failed to give satisfactory results, a systematic analysis of difficulties resulting from high pressures and weak down-hole formations led to the development of a reverse cementing technique. This method has now been used successfully for the past two years on all development wells drilled in the North Hassi- Messaoud field in Algeria. Its application required a modification of the regular differential fill-up equipment and wellhead assembly. The particular drilling and cementing problems encountered in this field are described in detail along with the technique and equipment used to solve them.

Introduction

A regular drilling schedule for a North Hassi-Messaoud well can be divided into four main steps (Fig. 1):1. A 17 3/8-in. hole is drilled from 0 to 750 ft using a 10 lb/gal bentonite mud improved with CMC (sodium carboxymethyl cellulose). A 13 3/8-in. casing is set and cemented up to the surface.2. A 12 1/4-in. hole is drilled from 750 to 1,800 ft using the same mud. At this depth the mud is converted to a salt-saturated type with a density increasing from 11 to 12 lb/gal. The hole is drilled to 7,500 ft, where an intermediate 95/8-in. casing is set.3. An 8 3/4-in. hole is drilled to 11,000 ft using the same salt-saturated mud weighted with barite up to 18 lb/gal. A 7-in. production casing is set on the top of the pay zone, the Cambrian sandstones.4. The reservoir is cored with 5 15/16-in. diamond core heads using a 12- to 13-lb/gal oil or water base mud.

Why Conventional Cementing Techniques Fail

Difficulties in Drilling the 8 3/4-in. Hole

Three major difficulties are encountered during the drilling of the 8 3/4-in. hole.

High-Pressure CaCl2 Formation Water

At 8,500 ft in the lower Jurassic, a high pressure, 8,500 psi, CaCl2 -saturated water producing formation is encountered. This formation consists of thin beds of porous and locally vesicular dolomite. The water contains 370 ppm of free HCO3 and 430,000 ppm of CaCl2. Mud contamination by this fluid is spectacular. To prevent this water from coming into the hole during drilling, a mud weight of 17 to 18.5 lb/gal is required. The exact amount depends on variations in permeability and the existence of fine fissures in the formation. However, when making trips, some of this water comes into the hole. It varies from 6 to 90 bbl and badly contaminates large amounts of mud which have to be circulated out and separately reconditioned.

Plastic Clays

Located between two massive Triassic salt beds, a clay zone about 15-ft thick is encountered at 9,500 ft. These clays are sufficiently plastic so that they continuously extrude into the wellbore. The only remedy is the use of adequate mud weight (17 to 18.5 lb/gal) to balance the formation. Other methods to control these clays (use of shale control type or extreme low filtration water base muds) have failed.

JPT

P. 146ˆ
Numerical Simulation of Combined Reverse Combustion and Steamflooding for Oil Recovery in a Utah Tar Sand
Authors: Lasaki Gbolahan O. , Martel Richard , Fahy John L.
Published: December 2007

This paper presents the design of the U.S. DOE Laramie Energy Technology Center's (LETC) Project TS-4, which involves numerical simulation of both in-situ reverse combustion and steamflooding. The simulator showed that the combustion could be limited and contained in a middle 10-ft [3-m] interval with a correlatable high-permeability streak within the 65-ft [20-m] pay zone of the upper Rimrock tar sand formation in Northwest Asphalt Ridge, Uintah County, UT. A high-transmissibility path was necessary to obtain adequate injectivity and sustain a stable reverse combustion. Combustion "echoes" developed and the front changed into a forward mode as the formation pressure increased and at very low air-injection rates. Oil recovery by steam injection was accelerated in a formation preheated by a reverse combustion.
An Improved Interpretation Method for Salt Mud Logging
Authors: Towle Guy
Published: December 2007

The increased usage of the FoRxo, Guard and gamma combination of logs in salty muds has led to the development of interpretation techniques which are fast and simple. This is possible because:The effects of bed thickness on both FoRxo and Guard logs are minimal and in moot cases may be neglected.With salt muds, true formation resistivity, Rt, is linearly and directly proportional to recorded Guard log resistivities over a wide range of conditions.Likewise, invaded zone resistivity, Rxo is approximately equal to recorded FoRxo resistivities.

This direct reading of these two vital parameters makes possible a fast but accurate visual location of all zones of interest. The same characteristics of the logs also make possible simplified interpretation curves to calculate both porosity and wager saturation.

Inasmuch as shaly sands are best measured without the disturbing influence of fresh waters, their interpretation is greatly enhanced by this system of logs.

For this technique to be used, the following conditions must be fulfilled:The zones of interest must be invaded by mud filtrate.The ratio of resistivities of mud filtrate to connate water must be known and the ratio must not exceed 10.Mud filtrate resistivity must be known.Mud cake thickness must be small.

Field examples are given which exhibit the inherent features as well as the disadvantages of the proposed techniques. Simplified charts for interpretative procedures are also presented.

In conclusion, the FoRxo, Guard and gamma logs provide a detailed log of the lithology from which porosity and water saturation may be calculated in detail by a simple interpretation method when certain conditions exist. The logging system also provides an improved method of interpreting shaly sands when both formation water and mud filtrate are highly conductive.
A New Nuclear Log for the Determination of Reservoir Salinity
Authors: Stroud Stanley G. , Schaller Herman E.
Published: December 2007

The salinity log was developed as a means for determining the presence and degree of salinity in formations surrounding the borehole. Being a radiation- or nuclear-type log permits its application in wells that have been cased and in wells where air or other gases may have been the drilling fluid.

Two curves ("chlorine" and "hydrogen") are recorded simultaneously with a single detector, and these curves are compared in the salinity determination. The two curves have been independently calibrated to show their response to changes in salinity and borehole size.

The salinity log has been run successfully in various oil-producing areas of the United States and Canada. Because of changes in the invaded zone with time, the log is most useful when run several days after cementing casing in the well.

Introduction

Everyone familiar with the interpretation of electric logs recognizes that in many cases these logs do not provide positive answers. This is particularly true of the logs that were recorded five or more years ago.

To at least partially satisfy the needs created by these limitations of the electrical jog approach, the salinity log was developed. In addition to not having some of the open-hole limitations of the electric log, the radioactive-type salinity log can be recorded through casing. It is believed that the invaded zone undergoes changes subsequent to the setting of casing in a well. This change may be effected by fluid migration, diffusion of formation fluid and drilling filtrate, gravity segregation, etc., and the rate of change will be influenced by the types of fluids involved, formation permeabilities and pressure differentials. Therefore, the maximum value from the salinity log probably will be realized by running it after sufficient time has elapsed subsequent to setting casing to allow the invaded zone to have effectively dissipated.
Thermodynamic Modeling of Quaternary Systems: Oil/Brine/Surfactant/Alcohol
Authors: Kilpatrick Peter K. , Scriven L. E. , Davis H. T.
Published: December 2007

Surfactant flooding for EOR results in multiphase oil/brine/surfactant/alcohol mixtures. Because alcohol and surfactant do not partition among the phases in constant proportion, thermodynamic modeling of quaternary systems is necessary in an accurate treatment of phase equilibria in these systems. We describe here the quaternary version of a free-energy-based equation of state (EOS). The systematic computation of phase equilibria in a quaternary system begins on the binary edges and ternary faces and proceeds by numerical continuation through the higher dimensional composition space. We expedite the computation with knowledge of the limits of thermodynamic stability—the spinodal surfaces—and all critical points that lie on those surfaces. This preliminary calculation indicates those regions in which solution of the nonlinear equations of phase equilibria will suffer from slow numerical convergence. Multiphase equilibria are searched out by both parametric and compositional continuation. The results provide the basis for understanding the trends of three- and four-phase equilibria in oil/brine/surfactant/alcohol mixtures.
Computing Techniques for Water-Drive Reservoirs
Authors: Hicks A.L. , Weber A.G. , Ledbetter R.L.
Published: December 2007

A procedure which makes use of both analog and digital computers has been developed for predicting the pressure-production behavior of water-drive reservoirs. The electric analyzer is used for matching the past pressure and production history of the reservoir and inferring the physical characteristics of the aquifer. When the history has been matched, a set of base curves called "influence functions" are derived and the future behavior of the reservoir is calculated from these curves.

Introduction

Electric analog methods are particularly well-suited for complex water-drive problems. Like all other methods of analyzing water-drive reservoirs, however, analog methods are subject to certain limitations. One of the more obvious and serious of these results from inaccurate or insufficient knowledge about physical characteristics of the reservoir and aquifer. However, it is not insurmountable because the unknown characteristics can usually be inferred from the reservoir's previous behavior. Simons and Spain have shown that even with scant reservoir data and limited production history, electric analyzer studies can provide useful and reliable results.

Aside from this limitation on analyzer predictions, the main disadvantage has been lack of a technique for keeping predictions abreast of latest production forecasts. Pressure behavior of a reservoir depends on the rate at which fluid is withdrawn; it is therefore necessary to specify the future withdrawal schedule before the future pressure behavior can be calculated. Conventionally, the electric analyzer predicts pressure behavior for a specific production schedule. If this schedule is abandoned in favor of some new one, as is frequently the case, either the study must be rerun or results adjusted in some manner. The usual procedure is to predict pressures for several different forecasts covering a wide range of production rates. Pressures for specific rates other than those studied can then be approximated by interpolating between the analyzer predicted curves. However, reliability of this type of prediction is doubtful.

This paper describes a technique for predicting future behavior of water-drive reservoirs that retains all advantages of electric analyzer analysis and eliminates the main disadvantage. That is, the analyzer is used conventionally to infer unknown reservoir parameters from the pressure history, but not to predict the future behavior directly. Instead, a derived set of base curves, called influence functions, can be used to calculate future behavior for any production schedule.
Automatic Data Readout Cuts Equipment and Labor Costs In Oklahoma Waterflood Project
Authors: Verseman C.S.
Published: December 2007

Automatic data readout is being utilized at seven LACT batteries in the North Burbank Unit to determine BS AND W, temperature and gravity. This results in a more efficient operation by increasing the accuracy of determining the three required functions for selling crude oil and by reducing operating labor. The paper covers the type of equipment utilized and the operating characteristics of the system.

Introduction

The North Burbank Unit, a waterflood project, is located in the northwestern portion of Osage County, Okla., Phillips Petroleum Co. is the operator. The unit was started in 1951 and presently has nine LACT systems, two manual tank batteries and 13 water-injection stations. The present average daily production is 24,500 bbl of oil and 175,000 bbl of water. Water is injected into the Burbank sand and recovered through a completely closed system. Fig. 2 is a typical LACT system and water- station installation. A basic dump-tank type system is used for the North Burbank LACT. Vessels comprising a system (see Fig. 2) are the 95-bbl meter tank, the 61-bbl pipeline sump and one 545-bbl surge tank. Four other stock tanks in series furnish the emergency storage for both water and oil. Flow of merchantable oil is from the heater treater to the surge tank, through the transfer pump to the meter tank, into the pipeline sump and then to the pipeline pump-quite conventional for LACT systems throughout the industry. Maximum capacity is approximately 7,000 B/D. This delivery volume depends upon the capacity of the transfer and pipeline pumps. An automatic-data-readout system is used at 7 of the 10 LACT installations. This equipment eliminates the need for storing and analyzing crude-oil samples. BS AND W, temperature and API gravity are measured electronically each time the meter tank fills. Measured values are stored on electrical-impulse counters for readout as required by the Production Dept. to determine daily oil production and by the various pipeline companies to write their weekly run tickets.

Typical Fill and Dump Cycle

Following is a description of one fill and dump cycle starting with the meter tank empty (see Figs. 1 and 2 -- a block diagram of the data- readout system and an LACT flow sheet, respectively). When the transfer pump starts, oil flows through the BS AND W cell to the meter tank. The BS AND W monitor continuously measures the volume per cent of BS AND W in the stream. This value is digitized by the averager and pulses are stored on a counter. Since this is a rate function (pulses/minute/per cent BS AND W), the time (minutes) required to fill the meter tank is also digitized and accumulated on a counter. When the tank is full, the transfer pump stops and BS AND W data are no longer digitized. However, the monitor continues to analyze the sample of oil in the monitor pump-bypass stream from the surge tank and will shut down the system if excess BS AND W is detected.

JPT

P. 473^
Flow Through a Porous Medium With Periodic Barriers or Fractures
Authors: Chirlin Gary R.
Published: December 2007

Apparent permeability of a reservoir may be affected by local variations in permeability whose extent and location are not known in detail. One way to approximate this condition is to postulate a regular pattern of typically shaped and oriented inclusions.

An example is the presence of a large number of very thin, relatively impermeable shale streaks distributed throughout an otherwise homogeneous reservoir. If these barriers to flow generally are oriented alike, then at a scale that is large compared to the individual barriers, apparent permeability will be anisotropic, being higher parallel to the barriers than perpendicular to them. Discontinuous horizontal shale streaks can be responsible for reduced vertical oil drainage to the pumping well1; therefore, a reasonable prediction of vertical permeability in such settings can be of value.

This paper examines the special case of a periodic array of infinitely thin, impermeable barriers opposed to single-phase, two-dimensional (2D) flow. Results provide a quantitative picture of the importance of barrier geometry and arrangement to the apparent anisotropy of permeability. The problem setting, formulated previously,2,3 allows a closed-form analytical expression to be obtained for anisotropy as a function of barrier geometry. However, a previously published solution3 is incorrect.2,4 The purpose of this paper is to present a correct solution and to discuss some of its consequences. Analytical results for this and other geometries, in two and three dimensions, have been developed previously.2 Numerical results for this problem are also available for both single-phase5 and two-phase (gas/oil)1 flow.
Some Possible Applications of Thermal Recovery in Utah
Authors: Covington R.E.
Published: December 2007

The bituminous sandstones of the Rocky Mountain region have significant reserves of oil. Production costs of the reserves must be reduced to be equal to or lower than the cost of crude oil produced by conventional methods. Three Utah deposits alone, Sunnyside, Vernal (Asphalt Ridge) and Whiterocks contain proved reserves of 875 million bbl of oil and "possible" reserves in excess of one billion bbl. In addition, there are at least six more deposits of asphaltic sands which contain substantial reserves within the state.

The most important deposits in Utah from the standpoint of thermal recovery are those of the Sunnyside area, Carbon County, Utah and the Asphalt Ridge-Vernal deposits, Uintah County, Utah. Two other areas which have thermal recovery potential are the bituminous sandstones of the Whiterocks area, Uintah County, Utah and the San Rafael Swell-Nequoia Arch area in Emery, Wayne and Garfield counties, Utah.

A preliminary evaluation of these four areas is discussed from the standpoint of geology, reservoir engineering, costs, markets and future development possibilities. These four, and perhaps three of the six areas of lesser importance, compare favorably with areas now being developed by thermal methods in California, Oklahoma, Texas and Kansas.

Introduction

The threat of large-volume, low-cost imported oil moving into the United States, combined with ever increasing exploration, drilling, completion and production costs, makes it imperative that the American oil industry take a long, hard look at the tremendous amount of oil in the bituminous sandstone deposits, in oil shale reserves and in shallow-to-moderate-depth depleted or semidepleted fields where production has declined beyond the point of profitable return on production costs.

For example, prior to 1950 the only method considered at all feasible for producing the bituminous sandstones of the Rocky Mountain region was by either conventional or strip mining and extracting the bitumen through various types of separation processes.
A New General Model of Fluid Loss in Hydraulic Fracturing
Authors: Settari A.
Published: December 2007

This paper gives a new formulation of fluid loss in hydraulic fracturing that is much more general than the classical theory while retaining its simplicity. The model allows many parameters to vary during filtration and can, therefore, simulate nonlinear effects.

The model has been validated against laboratory data for Newtonian fluids and crosslinked gels. The results show that the finite length of the core, viscosity screenout, and shear sensitivity are important parameters that can be represented by the model. The standard analysis gives values of leakoff coefficients that will give incorrect, considerably higher leakoff when applied to field conditions.