Abstract To prevent gas wells from load-up, it is necessary to study the cause of load-up and condition for liquids to accumulate in wellbore. The paper adopts the view that the liquids droplets entrained in gas wells tend to be flat shape and deduce new formulae for continuous removal liquid from gas wells. The results calculated from the formulae are smaller than that of conventional Turner's. However, the predicted results accord with practical situation of gas wells in China gas fields. In addition, for the easier application purpose, the paper put forward simple formulae from the deduced formulae under analyzing different factors affecting removal liquids from gas wells. The model explains why many gas wells produce without load-up when the producing rate is by far smaller than that of Turner's minimum producing rate. In order to help engineer working in gas fields judge load-up effluence on gas well production, the paper analyzes the production performance of load-up and near load-up as well as unloading gas wells through wellhead producing performance figures. Introduction Gas produced from reservoir will, in many cases, have liquid phase material with it, the presence of which can accumulate in the wellbore over time when transporting energy is low enough in the low pressure reservoir. The liquids accumulated in the wellbore will cause additional hydrostatic pressure on reservoir, which results in continued reduction of available transportation energy and affecting the production capacity. In some cases, it even causes gas wells to die. So it is essential to investigate the cause for gas-well load-up and to determine the minimum gas flow velocity and rate for gas wells to transport liquids to surface. Turner 1 compared two models, that is, the continuous film model and entrained drop movement model in 1969. He proved that liquid droplets entrained in the high velocity gas were more adequate for explaining gas-well load-up and used the model to investigate load-up of gas wells. Under supposing that the liquid droplets was spherical. Turner deduced the formulae used to calculate the minimum gas flow velocity and rate to remove liquid droplets with +20% adjustment. The minimum gas flow velocity and rate are known as the terminal velocity and critical rate. Turner also suggested that in most instances wellhead conditions controlled the onset of liquid load-up and the gas/liquid ratio in the range of 1370 to 178571 stdm 3 /m 3 did not influence the terminal velocity and critical rate. It is found that there are many gas wells producing rate much below the minimum flow rate calculated from Turner's critical rate formula and these wells still keep in good production state in China. To obtain the relatively accurate critical producing rate, the engineers in China gas fields adjust the Turner's critical rate with reduction by 2/3. Steve 2 found that the unadjusted liquid-droplet model tended to offer a better match of the field data according to two sources collected by him. The model still can not get suitable critical rate to explain the phenomenon of some gas wells which should be loaded up with his model but are not load-up in China natural gas fields. This paper presents formulae for predicting the terminal velocity and critical rate after analyzing liquid drop movement in high velocity gas stream. The calculated results with the present model are in conformity with the practical daily production record of gas wells. For the easier application purpose, the paper put forward simple formulae from the deduced formulae under analyzing different factors affecting removal liquids from gas wells. Steve 3 analyzed the behavior of load-up, near load-up and unload-up gas wells in wellbore. The paper shows the production performance of load-up ,near load-up and unloaded gas wells with wellhead producing rate figures through which engineers can have more understanding the effect of load-up on gas well production performance.

Abstract This paper presents a new production method in which the reservoir energy spent to lift the production from perforation-depth to the dynamic liquid level is replaced by surface energy, and consequently the well daily rate and cumulative production is increased by 200 - 250 %. The method can be used in any well at any time. The paper is based on the analysis of how the reservoir energy generated by the expansion of the reservoir fluids is used to produce the well: PROFITABLE USAGE: Moves the production through the pay zone into the well bore WASTEFUL USAGE: Sends the reservoir energy to: Overcome the liquid friction along the productionflow path. Lift the production from perforation-depth to thedynamic liquid level. Present production practice recognizes and reduces only the reservoir energy wasted to overcome the liquid friction through the pay zone by using better and cleaner perforations, acidizing, fracturing, and other techniques. When less reservoir energy is used to overcome the frictions through the pay zone, the well performance, in both rate and cumulative production, is increased. To date all artificial lifting methods are spending surface energy only to lift the production from the dynamic liquid level to the surface. However, the energy needed to lift the production from perforation-depth to the dynamic liquid level, the largest waste of reservoir energy, is now overlooked and has not been recognized as the most important way to significantly increase well performance. The proposed new production method substitutes the reservoir energy by surface energy in order to lift the production from perforation-depth to the dynamic liquid level. Accordingly the well performance in day rate and cumulative production is increased by 200 - 250 % compared to the actual well performance. The quickest and easiest way to produce the well according to the new production method, is to run a subsurface compensated plunger pump assembled from the API Spec-11AX parts, and work with the same beam pump. A subsurface compensated pump, is a liquid lifting device, which can not be drawn by the well pressure.

Abstract Crystal modifier chemistry is fast becoming very important in the enhanced production capacity of crude oil fluids. These products have been used for many years in offshore and refinery applications with a high degree of success. However, the broad usage of these chemicals in production areas has been spotty at best and often underutilized. Because of the incentive of increased fluid production resulting from crystal modifier application, producers have been more receptive to the usage of these types of treatment chemical applications. Considering this increased willingness of producers to incorporate these chemicals in their treating chemical programs it was important to study the various application methods by which these products can be introduced into the systems requiring treatment. Since, not all wells are equipped with capillary injection strings, or have backside access to chemical injection other methods such as squeeze applications are considered. Thus, laboratory testing and field test results are discussed in this paper. Background 1Considerable research and development have gone into the development of chemicals to address the problems of paraffin wax accumulation in oilfield production and transport operations. Development of these specialty chemicals requires that meaningful methods of testing be undertaken that will accurately predict the effectiveness of these chemicals in an application. To this end many testing methods have been developed to closely approximate field conditions of temperature, pressure pipeline configuration and pumping requirements. The degree to which these methods correspond to actual field and equipment conditions determines the reliability of such tools as predictive means by which field behavior can be determined. Although the theoretical justifications for the use of these measurement techniques are well founded the acceptance of them, by oil companies, as reliable methods must be thoroughly documented. Documentation of the reliability of these methods requires considerable effort by the service companies who employ them. Many times the documentation is found lacking by the oil companies, and the acceptance of the data generated by these tools and techniques is discounted as virtually meaningless. Thus, service companies are challenged to compare the predictions derived from these laboratory techniques to the effects experienced in field applications. The following discussion will cover some of the laboratory testing conducted, and relate it to the results obtained in field applications of the product chosen from these laboratory tests. Discussion Pour Point and Viscosity Testing ASTM D-97 Pour Point Testing (see figures 1 and 2) has been used for many years as a means of determining the effectiveness of chemical additives on the behavior of waxy crude oils. Can this method be used as the sole criteria for effectiveness? The answer is generally no, however when a crude oil shows a high tendency to congeal or gel and little or no tendency to deposit this test might serve quite well as means of determining an effective treatment. However, viscosity measurements should be conducted in combination with the pour point tests to determine the magnitude of a chemically induced physical change. Why is it necessary to add viscometry measurements to the ASTM D-97 Pour Point data? Pour point measurements involve periodically tilting a tube containing a thermometer and treated or untreated oil samples over a progressively declining temperature range, and observing for movement. The shear imparted by this technique is extremely low, and can represent very small changes in viscosity. Therefore, viscosity measurements avoid the ambiguity introduced by this method. Additional information that is of value in determining the behavior of waxy crude oils under various conditions is also obtainable by the use of viscometry (e.g., yield point, shear stress vs. temperature, and shear stress vs. viscosity etc.).

Abstract The analysis of oil production data using decline curves is a modeling and forecasting technique. Actual production rate and time data are history matched to a theoretical model using specialized graphs known as type curves. This study begins with a review of the previously developed decline curve construction and analysis methods. It consists of reproducing Arps-Fetkovich type curves and the derivative type curves for advanced decline curve analysis. A Program was developed to generate the dimensionless rate-pressure and time data necessary to construct Fetkovich type curves. Combining the analytical solution derivative for transient flow based on numerical analysis, and the empirical solution derivative for boundary dominated flow develops the derivative type curves. The type curves is used to identify the transient versus depletion stages and to estimate reservoir parameters and future decline paths. Field production data are generally difficult to match with the type curve for this reason a Universal Fitting Equation is proposed as an alternative to manual type curve matching. This equation combines both Arp's empirical equation and Fetkovich analytical solutions. It equation offer the following advantages: Fitting with the equation is more precise than type curve matching to obtain reservoir dimensionless radius reD, Arp's exponent b, matching points q/q Dd , and t Dd /t. The real production data can be fitted directly by the equation without using smoothing techniques. The radial and pseudosteady state regions are determined automatically and easily from fitting. Some production data that were insufficient to be analyzed with manual type-curve matching can be interpreted with the Fitting Equation. This procedure has been applied to some Real field data from Hassi Messaoud field cases and it has given significant results. Introduction Decline curves are the most common means of forecasting production and estimating the value of oil and gas wells. The earliest literature refers to a mathematical decline analysis approach presented by Arnold and Anderson in 1908. Arps developed the standard exponential, hyperbolic and harmonic decline equations in 1944. In 1973, Fetkovich 2 proposed a dimensionless rate-time type curve for decline curve analysis of wells producing at constant bottom-hole pressure. These type curves combined analytical solutions to the flow equations in the transient region and empirical decline curve equations in the pseudo-steady state region. This approach to decline curve analysis, known commonly referred to as "advanced decline curve analysis", has become widely used as a tool for formation evaluation and reserves estimation. In 1980, Fetkovich 2 demonstrated that decline curve analysis not only has a solid fundamental base but also provides a tool with more diagnostic power than had been previously suspected. Fetkovich 2 constructed log-log type curves, which combine all these equations developed by Arps 1 with the analytical constant pressure infinite and finite reservoir solutions. He showed that log-log type curves could be analyzed by the type curve matching technique. The uses of pressure derivatives in well test interpretation was introduced by Tiab 3 in 1975 and Bourdet et al. developed the use of derivative type curves for transient well test analysis in 1983. By multiplying the pressure derivative by the time, (or equivalently, by taking the derivative of pressure with respect to the natural log time), they were able to display both the pressure and the pressure derivative type curve on a single set of axes.

Abstract This work presents procedures on how to apply a newly developed method to simultaneously determine the average reservoir pressure and initial fluid in place using surface production data and flowing bottom hole pressure. This new method is derived from a combination of a generalized material balance formulation and pseudo steady state theory. Reservoir simulation was used to generate production history and flowing bottom hole pressure via hydraulic tables, which were used to calculate average reservoir pressure and initial fluid in place in order to validate the accuracy of this new method. Five examples were investigated for production with vertical and horizontal wells in oil and gas reservoirs at constant rate or constant flowing bottom hole pressure. Calculated initial-fluid-in-place and average reservoir pressures agree very well with that derived from reservoir simulation. This new method is useful in analyzing surface production data in the following conditions: reservoirs significantly lack data, buildup tests are inconclusive in determining average pressure, buildup tests are expensive or difficult to run such as wells in tight and over-pressured reservoirs or with subsea completion. Introduction A frequently encountered difficulty in material balance calculation is lack of shut-in reservoir pressure. Without shut-in reservoir pressure, it is very difficult to perform material balance calculation. However, production data seems to be available most of the time. If we can make use of sand-face production rate and flowing bottom hole pressure, then it is possible to develop a new method which can be used to determine average reservoir pressure and initial fluid in place simultaneously. This new method does not require shutting-in of production, nor does it require a prior knowledge of drainage area, shape factor, and permeability under pseudo-steady state condition. Objectives The objectives of this study are to present procedures on how to simultaneously determine average reservoir pressure and initial fluid in place from production data and flowing bottom hole pressure for oil and gas reservoirs, and to test the validity of this new method with five examples employing vertical and horizontal wells. Mathematical Formulation This section gives a brief summary of a generalized material balance formulation of hydrocarbon fluid at reservoir condition. Detailed derivation of all the equations presented in this work can be found in reference and definitions of symbols are given in the nomenclature section. Oil Reservoirs (I) Material Balance Equations for Cumulative Fluid Production For oil reservoirs, the material balance equation with constant C f is represented by equation (1). Equation (1) (II) Material Balance of Oil Production Rate Assuming no water influx and negligible water production, the material balance equation of oil production rate at reservoir condition is represented by equation (2). Equation (2)

Abstract One frequently encountered difficulty in material balance calculation is lack of shut-in reservoir pressure. This work presents a new method that can be applied under pseudo steady-state conditions to simultaneously determine the average reservoir pressure and initial fluid in place using only surface production data and flowing bottom hole pressure. This new method is derived from a combination of a generalized material balance formulation and pseudo steady state theory and is applicable to both oil and gas reservoirs for single-phase flow with no water influx. This method does not rely on pressure build-up tests, knowledge of drainage area or permeability, but it requires flowing bottom hole pressure. For constant flowing bottom-hole pressure or variable production rate, this work presents an algorithm to convert fluctuating or constant flowing bottom hole pressure into corrected flowing bottom-hole pressure with a decline rate essentially identical to that of average reservoir pressure. Methods for analyzing transient flow are also discussed in this work. This new method is useful in analyzing surface production data and flowing bottom hole pressures for reservoirs significantly lacking data. Introduction A frequently encountered difficulty in material balance calculation is lack of measured reservoir pressures, which are usually obtained from shut-in build-up tests. Without shut-in reservoir pressure, it is very difficult to perform material balance calculation. However, production data seems to be available most of the time. If we can make use of sand-face production rate and flowing bottom hole pressure, then it is possible to develop a new method which can be used to determine average reservoir pressure and initial fluid in place (IFIP) simultaneously. This new method is derived from a combination of generalized material balance method and pseudo-steady state theory to determine reservoir pressure and initial fluid-in-place simultaneously without relying on pressure build-up tests. Furthermore, this new method does not require shutting-in of production, nor does it require a prior knowledge of permeability, drainage area, and shape factor under pseudo-steady state condition. Objectives The objectives of this study are to present detailed mathematical derivation of a new method, which can be used to simultaneously determine average reservoir pressure and IFIP for oil and gas reservoirs without relying on pressure build-up tests and to provide solution algorithms of this new method. Mathematical Derivation The material balance of hydrocarbon fluid at reservoir condition states that the initial hydrocarbon pore volume is equal to the current hydrocarbon pore volume plus the hydrocarbon pore volume reduction due to pore volume reduction, expansion of initial water saturation, water influx, water injection, and water production. This concept is expressed in equation (1). Detailed derivation of equation (1) can be found in references (1, 2, 3, and 4). Definition of each symbol is given in nomenclature.

Abstract During the '90s, the introduction of battery powered electro-mechanical intervention tools increased the versatility of slickline service and changed its image from a simple method that performed mechanical workovers to a complex service technology that could provide safe, cost-efficient alternatives for: locating downhole tubular goods/profiles producing quality logs from downhole memory surveys at half the cost of traditional services accurate depth measurement for support of all new completion technologies setting packers without explosives perforating or cutting tubing or casing. Slickline has again expanded its capabilities. In addition to its proven performance for well remediation, maintenance, and pressure control applications, the new enhancements to the self-powered slickline tools can now be used to perform diagnostic and conformance control functions requiring memory production logging. Applications that require electrical initiation or mechanical manipulation at the tool interface can now be performed with slickline and battery power, insulating the tools from the surface equipment. Mechanical signals transmitted through the wire control the tool start and stop functions and provide real time position telemetry. As a result of the advances in service tools, slickline has increased the scope of its services without a compromise to operational safety and job efficiency and offers the most cost efficient services in well workovers. The case histories will describe how the electro-mechanical intervention tools provide a cost-effective alternative to traditional cased-hole logging systems for many applications as well as many operations that traditionally had to be performed by other service options. History of Service and Equipment Development Traditionally, slickline servicing has been able to provide an effective means for performing well maintenance by high speed mechanical deployment, manipulation, and retrieval of downhole service tools in all types of wells, including those with high pressure and flowing well conditions. Its portability has allowed it to be cost efficient for performing these services in remote locations and on satellite platforms. The introduction of electro-mechanical intervention tools combined with accurate surface measuring instruments has significantly changed the slickline operating envelope. The slickline tools that make the new services possible includes the following: 1 An electronic measurement system (AMS) that automatically corrects measurement inaccuracies resulting from line stretch and environmental stress factors. 2 An electronic triggering device (ETD) that enables safe detonation of explosive devices. A battery-operated, electro-mechanical tool that sets wellbore devices on slickline and braided line without pyrotechnic devices. 3,4 A slickline collar locator (SLCL) that accurately verifies collar locations in a tubing string. Data/job loggers (or acquisition software systems) that connect to the electronic measurement system to graphically record dynamic wireline information. While each of the above tools has been instrumental in its own right for the increase of slickline usage, the most significant factor in the increased capabilities of slickline for low-cost intervention has been the methodology that unites the individual tools into systems that can increase job efficiency. Fig. 1 shows a typical slickline service unit and the equipment that can be used in combination to enhance the service capabilities. The tools represented in this figure are discussed in the next sections.

Abstract Much recent attention has been recently given to depletion of U.S. natural gas reserves, particularly since many forecasts predict a 30 TCF annual gas market. A comprehensive look at the way initial production, decline rates, and reserves have changed over the last 30 years in Texas, the source of 1/3 of the country's natural gas, leads to concern about whether current drilling activity will be able to maintain the current supply, much less increase gas production 1 . The decline rates in new Texas gas wells have changed from about 20% in the first year for wells drilled in the 1970's and 1980's, to more than 55% for wells drilled in 1998 and 1999. At the same time, the contribution to the state's supply from new wells has sharply increased from 8% of the state's supply to more than 15%. Although the initial production rates from an average well have actually improved from a low of 15 MMCF per month in the early 1980's, to 44 MMCF per month in 1999 due to improved completion technology and horizontal drilling, the combined effects of fewer completions and high decline rates suggests that a decrease in Texa's production capacity may occur in the near future. Drilling above the current activity will be necessary to sustain the state's gas production. Normalized rate vs. time curves were developed for each year since 1970 to obtain initial rates and decline profiles. The curves were extrapolated to an estimated ultimate recovery, changing from 6 BCF per well in the early 1970's to 1 BCF per well in the late 1990's. Introduction Texas has been the source of 39% of the approximately 882 TCF marketed in the U.S. since 1945. The state currently supplies about 32% of the country's natural gas and holds 27% of the proved reserves 2 . By any measure its contribution to the U.S. supply is significant. Natural gas reserve-to-production ratios have been fairly constant in recent years for both the U.S. and Texas, and stand at 8.7 years and 7.4 years, respectively, for the year ending in 1999.

Abstract A compact cyclone multiphase meter (CCM meter) developed by Statoil andKværner Process Systems utilizes a compact gas liquid cyclone to separateliquid and gas, before individual measurement of the two phases by conventionalsingle phase instruments, followed by re-mixing downstream of the measurementsection. The most unique feature of this cyclone is the simple control schemewhich provides for large turn down ratios. The instrumentation has beenimplemented into the water cut analyzer electronics to provide for a completestand alone system. Field test data will be presented along with its impact onreservoir management. Introduction In the past, geological and reservoir engineers have focused oninterpretation of data obtained by wirelines and other bore hole techniquesalong with summary production numbers to determine and optimize wellproduction. Most of this information is obtained at a very high cost and canchange overnight due to many factors beyond the engineer's control. Data suchas water or miscible injection rates and production pressures, temperatures, flow rates of oil, water and gas are obtained on a regular basis and are sharedamong the various engineering groups. This latter data is the day-to-dayoperational information for evaluation of the production from a given field.The most fundamental information is contained in the well test data. This welltest data is typically taken once or twice a month in most fields in theAmericas. It is interesting to look at some expectations of prior periods in time. In1964, the following was stated by George Kite [1]: "Various arrangements for three-phase separators are in wide use but are oftenunnecessarily expensive and complicated; frequently they leave much to bedesired insofar as accuracy, operator convenience and adaptability toautomation are concerned. The instrumentation system discussed automatically and continuously meters andmonitors an oil water stream containing … or any combination thereof, and, without physical treating or separation, provides an accurate digital readoutof net clean oil volume, directly in barrels. No calculations, conversion factors, or interpretations are required; data arepresented instantly, continuously and cumulatively in the most usable form. Inaddition, electrical digital signals for remote counting and an electricalanalog signal for remote percentage water indication or recording are availableat the computer terminal block." Today, the industry is still stating that the current systems are expensive, operator intensive, inaccurate, and difficult to maintain. The proliferation ofSeminars, Joint Projects, Conferences and Workshops concentrating on"Multiphase Measurement" emphasizes the industry is looking for bettertechnology. The perfect solution would be compact, non-intrusive, low pressuredrop, accurate, inexpensive and simple to use. This is a good description ofwhat "Multiphase Measurement" is trying to accomplish. The question is how longwill it take to get there and to what specifications and price can each of themarkets requiring this withstand. In the meantime, the industry has not yetsolved the basic problems which have been plaguing it for 30 years.

Abstract In the United States both state and federal government have provided incentives in recent years to maintain production, increase production, and discover new production. On the state level, the incentives involve mostly abatement or rebate of severance taxes. Oklahoma and Louisiana (and possibly other states) have had severance tax relief statutes in recent years that are producer helpful in maintaining production in times of low oil prices. All of the incentives are noted but the two discussed most require no investment by the operator. This paper gives a brief history of the statutes which might be considered relatively generous. In the case of Louisiana, the major statute could be considered farsighted in nature. Oklahoma's incentives history shows a rapid willingness to adjust to help maintain production. The paper also comments on the applicability of use of the statutes. Introduction History shows (as can be noted from Fig. 1) that oil prices above $20/bbl have not been sustainable since the oil price crash of 1986. Reference 1 notes that major producing states with a large number of stripper wells including Oklahoma, Texas and New Mexico showed large percentage declines in 1998 due in part to low oil price and stripper wells (wells producing 10 BOPD or less) with lifting costs approximating $15/barrel. Table 1 (taken from Reference 2) shows stripper well data including well count, production, and reserves for Louisiana, Oklahoma, New Mexico and Texas. Based on post 1985 oil price history, it is not surprising that states have provided incentives to maintan production. This study does not attempt a thorough review of incentives provided by all states. As will be discussed herein, Louisiana and Oklahoma have provided useful incentives which have undoubtedly helped in maintaining production. In some respects, their major incentive tied to oil price could be considered somewhat more generous than anything provided by other states. The incentive appears to relate to the State's type production in some respects. They also become effective at a relatively high oil price. Although the current prices do not permit use of the incentives, it is worthy of note that a recent survey of Houston banks predicts oil prices in the 18 $/bbl range from 2000 through 2002 (Reference 3). Based on the premise that the oil incentives are comparatively generous, it is interesting that on a per barrel basis the State's overall take from oil including all taxes is relatively low. That fact can be noted from Fig. 2 which is taken from Reference 4. A non detailed review of the States's production incentives follows. Oklahoma A look at oil price history (Table 2) and production history (Table 3 and Fig. 3) gives some indication as to not only why the incentives exist but why they have been improved since being put into law in 1994. Based on 1996 producing well count (Reference 2), average per well production for that year was approximately three BOPD. Depletion state of the fields is also reflected by an average annual GOR of 3184 which can be derived from Fig. 3. Production on Fig. 3 is a composite of 21,484 producing properties which reflects a wide diversity of ownership and little room for economics of scale. Low revenue coupled with moderate to high operating costs leaves little room for profit. Thus, any reduction in the seven percent gross production tax would help significantly.

Abstract In highly fractured reservoirs, where gravity dominated recovery processes are employed, fluid contact measurements and isobaric mapping are useful tools for understanding operational and process changes. Monitoring fluid contacts accurately in highly fractured reservoirs has always posed a challenge due to limitations in the measurement tools. Gradio-manometer surveys and electronic fluid property surveys lack the depth resolution needed to locate contacts, and direct measurement methods are time consuming, messy and yield no secondary information for quality control. Fluid gradient measurement is the desired method; but historically, limitations in gauge precision or thermal response have made this method unattractive. An electronic pressure gauge using a silicon crystal sensor was shown to provide predictable response to strain under changing temperature and to provide the precision and accuracy needed for repeatable contact measurements and reliable pressure mapping. The pure silicon crystal has a small mass, a thin unbonded structure, and a temperature sensor for compensation placed in close proximity thereby decreasing the stabilization time required for true pressure recording.Rapid pressure measurement allows shorter, more frequent gradient stops; and consequently better data resolution for contact calculations. Replacing non-pressure based contact measurement techniques in a field where bottom hole pressure surveys were taken on staggered intervals saved real dollars. This was done by adding one to two days onto a pressure survey and eliminating the separate contact survey. Measuring both contacts and pressures concurrently reduced time-normalization problems and increased data confidence. Accurate, repeatable pressure measurements clarified details of operational changes on the reservoir management process, improved the data collection process, and reduced expenses to the operator. Introduction In highly fractured, gravity drainage reservoirs, much depends on the oil column movement throughout the reservoir. 1,2 In the past, several methods have been used to gather this information with varied success: fluid conductivity logs, gradiometer logs, fluid gradient analysis, and direct measurement "dipstick" methods. Conductivity logs located the water oil contact (WOC) by measuring the difference in electrical conductivity between water and oil; while marginally successful, they did not give suitable measurements of the Gas Oil Contact (GOC). Gradiometers were also tried but proved expensive to run and gave inaccurate results when run at reasonable speeds. First attempts at fluid gradient analysis were not accurate enough due to gauge precision limitations. Of the methods tried, the most consistent and simple was the bar or "dipstick" method. Quite simply, an angle iron was covered in talcum power and run in the well on slick line to an assumed GOC depth. The depth of the contact is calculated as depth run minus the talc free portion of the dipstick. A second run is made to find the WOC after painting the angle iron with a paste that changes color when it contacts water. Due to its direct measurement method and low cost, the dipstick method became the standard for years. Replacing the Dip Stick The dipstick method had three problems. It provided only contact information, therefore, a separate pressure survey was required to monitor bottom hole pressure across the field. The two surveys had to be time normalized in order to compare data. Dipstick operations are messy and require several entries into the wellbore (if the contacts had moved significantly, many entries were required). Fluid Gradient Contact Measurement. Monitoring contacts using fluid gradient measurements has been the method of choice due the secondary pressure information it provided and because it could be done with one trip into the wellbore. The procedure requires several stops to be made in the wellbore with at least one in each fluid phase. Fluid Gradient Contact Measurement. Monitoring contacts using fluid gradient measurements has been the method of choice due the secondary pressure information it provided and because it could be done with one trip into the wellbore. The procedure requires several stops to be made in the wellbore with at least one in each fluid phase.

Abstract The Permian Basin is a mature oil province where many fields are under secondary and tertiary recovery. Waterfloods abound and it is not uncommon to have wells that make 20 BOPD and 2000 BWPD. At today's oil price the economics of these fields are marginal on a good day. The operators of these reservoirs would like to be able to shut off some of the water production without losing a drop of their meager oil production. Ideally, the drop in water production would affect relative permeability and result in an increase in oil. The only technique available to shut off water has been the "plug-and-see" (also known as the hunt-and-peck) method. Experience with this technique indicates that in 60% of the cases either the water cut increases or the oil production decreases. If the reservoir engineers better understood where the oil and water were coming from they would be more successful in using plugs to decrease the water flow. There have been two major roadblocks to the successful application of production logging. First, the wells do not flow naturally so pumps are used. As a result the production logging string cannot get to bottom. Second, even if tools could be placed below the pump, conventional production logging tool strings cannot accurately detect oil cuts below 5%. Until the introduction of the new PS Platform* production services tool string, West Texas waterflood operators had no way to accurately determine what was happening downhole. The sensors on the PS Platform string not only measure very low oil cuts, but the tool string has also been placed below electronic submersible pumps (ESPs) in an ingenious rig-up technique that required a joint effort between Schlumberger Wireline and REDA. Once the pump is turned on and flow stabilizes, the sensors can measure very low oil rates accompanied by high water rates. This paper describes the use of the new technique on two wells in the Altura Midland Farms Unit. In both cases the PS Platform was deployed below an ESP and delivered high-quality answers that significantly impacted the economics of the field. These successes consequently lead to the use of the PS Platform sensors, in conjunction with TDT* Thermal Decay Time tool, in tertiary CO 2 floods. Introduction In 1989 Altura conducted a plugback program on 25 producing wells in their Midland Farms Unit. Before the program, these wells produced 847 BOPD and 25,515 BWPD; an average of 34 BOPD and 1021 BWPD per well. The plugbacks cost Altura $208,000 ($8000 per well). After the program, these wells produced 914 BOPD and 15,560 BWPD. The payout on the program was 6.1 months. Although this was an acceptable result, it obviously could have been better. Of the 25 workovers, 9 were successful and paid out within 6 months; 9 were actually better wells before the plug backs; 2 had payouts in excess of 5 years. This experience left Altura with a desire for a better technique to minimize water production in this field.

Abstract Several strategies have been employed in Wagner & Brown's Conger field of over 500 beam-pumped wells to reduce electrical power bills. The first involved a decision, early in development, to deliver the highest practical voltage to each wellsite. Later, as well count reached into the hundreds, full understanding of the distribution system, its power flow and line losses, required computer modeling of a combined electrical system that was previously metered by two separate primary meters. That modeling brought about elimination of power factor penalties and reduction of IOR power losses by optimum placement of capacitors. By coordinating the system protection devices such as primary fuses and upstream reclosers, the system reliability was improved and the production downtime was reduced. Placement of a digital PME with memory and computer download capability allowing scrutiny of field power usage in 15 minute increments led to overall power demand (KW) leveling and reduction of peak demand through installation of digital pump-time clocks. Current utility deregulation promises significant cost reductions for users flexible enough to alter or otherwise control the way in which they consume electricity. P. 149

Abstract Although High Density Polyethylene (HDPE) lined tubing has been used regularly as a corrosion barrier to protect tubing in water injection applications, it has had limited application as a corrosion/wear barrier in rod pumped wells. With a goal of reducing well failures due to rod/tubing wear and internal tubing corrosion, polyethylene lined (poly-lined) tubing was installed in 17 rod pumped wells in the McElroy Field in Crane, Texas. It was assumed that the liners would provide sufficient reductions in friction between the rods and tubing to reduce wear, and that the sealed system would further reduce failures due to corrosion on the tubing strings. The pilot test shows that the wells equipped with the polyethylene liners have outperformed their previous failure histories. Overall the average runtime without an internal wear/corrosion related failure to the tubing and without a wear related failure to the rods has increased approximately 400% among the subject wells. Runtime including all failures has increased over 300%. In addition the system has demonstrated that used tubing can effectively be used in a field where traditionally new tubing had been purchased to extend run times. In those cases where artificial lift designs were not changed after the poly-lined tubing was installed, there was a measurable reduction in the Polished Rod Load Range, Balanced Torque and minimum stresses in the bottom of the rod string. Overall average failure ratio for the pilot wells has declined dramatically from 4.3 to.59. P. 535

This paper was prepared for presentation at the SPE Permian Basin Oil and Gas Recovery Conference held in Midland, Texas, 23-26 March 1998.

Abstract Frictional forces acting on the rod caused by the rod reciprocating in the flowing fluid significantly affect the prediction and diagnosis of rod-pumping system performance. Available studies of the flow in the tubing combined with moving rods and couplings are limited to laminar flow. The flow is more likely to be turbulent, however, for liquids with low viscosity and for regions near the rod couplings. Therefore in the current study, turbulent flow in the annular region between the stationary tubing wall and the moving rod/coupling is considered. Computational fluid dynamics (CFD) is employed to simulate turbulent flow in the annular region with moving rods and couplings. Also, a simplified model using a mixing-length method is developed that is much more computationally efficient than the CFD code. The CFD code employing the standard k-model is used to predict turbulent fiction factors in the annulus with the moving rods and couplings. The simplified model is developed to predict turbulent fiction factors in the annulus with the moving rods. The results from these models are compared each other and with the available data published. In addition, the friction factors between the rod/coupling and fluid can be represented in terms of four parameters: the rod to tubing radius ratio, the coupling to tubing radius ratio, the fluid Reynolds number, and the relative rod velocity. P. 397

Abstract Two fields, Ozona (Canyon) and Sawyer (Canyon), with more than 4,000 total wells, contain the majority of wells in the Canyon Sand trend of Crockett, Edwards, Schleicher and Sutton Counties in Southwest Texas. Average ultimate recovery for the fields decreased from 1,100 MMCF/well for wells drilled in 1970 to 400 MMCF/well for wells drilled in 1985, then remarkably reversed the trend. Recently drilled wells (since 1991) are expected to recover an average 625 MMCF. Initial monthly production decreased from 15,000 mcf/month to 5,000 mcf/month in 1985 and then increased to the present 12,000 mcf/month. Average first year wellhead pressure continued to decrease throughout the 25 years studied to a present 1300 psig in Ozona and 700 psig in Sawyer. The data suggest that drainage interference began to be a factor in about 1985 in the more densely developed areas. Although the average well density was about 200 acres per well in 1985, the true density in areas of active infill drilling probably approached 120 acres per well. Present average density is 143 acres per well in Ozona Field and 131 acres per well in Sawyer Field, but many leases are developed on density of 80 acres or less. Introduction During the 1970's, the Canyon Sands of Crockett, Edwards, Schliecher and Sutton Counties, Texas became a significant source of new gas production (Figure 1). More than 4,000 productive wells have been completed in the Sawyer and Ozona Fields. Drilling activity since 1970 has varied, peaking in the mid to late 1970's and falling to a low in 1986 as gas demand from these fields fell. As development of the trend proceeded and fields merged, the Texas Railroad Commission ordered a number of the adjacent fields reclassified into either Ozona (Canyon Sand) Field or Sawyer (Canyon) Field. The two fields now contain more than 65% of the wells in the entire 6,000 well Canyon Sand gas trend. Sawyer (Canyon) Field was discovered in 1967 and produces gas from Pennsylvanian age deltaic or turbidite lenticular sands at about 5,200 to 6,500 feet. The field covers portions of Edwards, Schleicher and Sutton Counties, and contains some 2,200 active and abandoned wells. Ozona (Canyon Sand) Field is located almost entirely in Crockett County, west of the Sawyer Field, and trending deeper into the Val Verde Basin at about 6,500 to 7,500 ft. It was discovered in 1962, but, like Sawyer, was slow in development until the rise of air drilling in the early 1970's. Figures 2 and 3 show the development history of each field group. Both fields produce dry gas with small amounts of water from tight sands of 8-10% porosity and less than .1 md permeability 1 . There is core evidence that 1-2 inch streaks of significantly greater permeability exist within the larger sand lenses and these may enable the sands to produce in economic quantities. A study of estimated ultimate recovery, initial production rates, wellhead pressures, and well density was completed for each field. The study encompassed all 3,200 wells drilled since 1970 in the two Fields. The Ozona group of 1,270 wells included minor numbers in the adjacent fields of Ozona, NE (Canyon 7520), Ozona, North (Canyon), Ozona NW (Canyon) and Ozona, SW (Canyon, Lower). The Sawyer Field study of 1,950 wells included only those classified in Sawyer (Canyon) Field.

Abstract An oxygen activation log was modified for use in obtaining injection profile surveys in four short radius horizontal injection wells. The tool was run inside a workstring that was temporarily placed in the lateral. Injection was established down the well annulus and the tool measured flow rates at points in the annulus between the workstring and open hole lateral. From this data, a distribution of injection along the lateral could be determined. Three different stimulation techniques were used on the horizontal wells and the profile results provided valuable insight into the effectiveness of these techniques. Introduction The productive reservoir in the Slaughter field is the San Andres, a dolomite formation at a depth of 5000 feet. The field is located 100 miles north of Midland, Texas. Solution gas drive served as the primary recovery mechanism for the initially undersaturated crude. The reservoir has been under waterflood since the 1960's and other operators began CO 2 flooding in the 1980's. Texaco initiated a miscible CO 2 flood in 1994. Horizontal wells can improve waterflood and CO 2 flood sweep efficiency. 1,2 In order to realize this improvement, it is imperative that injection be evenly distributed along the entire lateral. Texaco has now drilled seven horizontal injectors on the Sundown Slaughter Unit, an 8684-acre property in the Slaughter field. These wells have lateral sections ranging from 589 to 864 feet. They were drilled at a slight angle and designed to penetrate all layers in the pay. This paper discusses part of the evaluation process for these wells. The lack of available equipment and techniques designed to work in a short radius, 4 1/2 inch open hole completion created a need for a new method to determine the injection profile. Figure 1 shows the location of the four wells where this new method has been applied. Reservoir Considerations The Slaughter field is located on the Northwest Shelf of the Permian Basin. Cyclic deposition resulted in a stratified reservoir with significant variation in porosity and permeability within the pay section. Core analysis shows that porosity ranges from two to 20 percent. Permeability varies from nearly zero to 50 millidarcies. A dense layer composed of mostly anhydrite with interspersed dolomite layer covers the reservoir and forms an excellent seal. The lower limit of the resesrvoir is defined by the top of a transition zone. Rock properties in the transition zone are similar to those in the pay zone. Due to the variation in reservoir properties between and within zones in the pay section, and the existence of layers within the pay that may act as flow barriers, it was important to verify that all zones are being flooded. Also, we desire to confirm that no thief zones existed in the curved section of the well above the pay zone.

Abstract Production data represent a source of information about the ongoing dynamic flow process in the reservoir. A proper analysis of these data might therefore give an indication of the relationships governing the fluid flow. Exploratory data analysis is one tool which can be used to extract the required information and to establish a statistical significance to the results. This paper presents a simple approach to examine the interwell communication and interference of a mature waterflood in order to identify and rank areas of potential improvement. Using this as a screening process we can identify areas with the best potential for further and more detailed studies. In addition some of the problems and limitations associated with analysis of production data are discussed. Introduction Is there an easy way of evaluating waterflood performance based solely on surface measurements in the form of rates and pressures? Although production data have always been a key part of any waterflood evaluation, no good answer has been given to what we can expect to get from such an analysis. Exploratory data analysis of production data is aimed at organizing and representing the data in an easy interpretive way. The analysis can take place at two levels, global and local. The global level will examine large scale trends (multiple wells), whereas the local analysis will focus on single well behavior and interwell relationships (well pairs). The use of production data as an analytical tool depends upon the quality and density of the data. More data of higher resolution and quality will yield significantly more information than irregular and poorly measured data. The quality of the analysis is therefore a direct function of the quality and the density of the measurements. The analysis of production data poses a particular challenge since we have a 3-dimensional data set mixing both the spatial and the temporal (time) dimensions. Stationarity assumptions along the spatial plane do not translate into stationarity along the temporal axis. Special care is therefore necessary when dealing with both the spatial dimensions and the temporal dimension simultaneously. In addition, the surface measured production data constitute a 2-dimensional spatial plane, which represents the dynamic behavior of a 3-dimensional reservoir. Another challenge is the size of the data set which comprises the production data. An efficient handling and representation is therefore important to obtain a clear interpretation. The primary objective of the methodology presented in this paper is to screen the field data to identify and rank areas of potential production improvement for a mature waterflood, in the form of changes to the individual wells, operational changes to the water injection allocation, infill drilling or pattern reorientation. This identification process depends upon the ability to extract information about the connectivity, sweep and interference among injection and production wells based on production data. Having identified potential areas of improvement, these areas can be further evaluated based on the geological knowledge and a more detailed reservoir study.

Abstract Historic "sweet spots", areas of well-to-well interference, and infill potential were determined for an 1800 well area of the OZONA (Canyon) field using a new approach that focuses on the age of the wells, their location, and production profiles. At the core of this new approach, termed "moving domain", is a mosaic of automated studies that draw statistical conclusions about well performance, depletion, and undrained acreage. Preliminary infill estimates in one to two weeks are possible and the technique is typically linked to conventional reservoir engineering to improve estimates. When applied to OZONA (Canyon), 1246 infill locations were identified with 636 Bcf of gas reserves. Introduction History. The OZONA field, located in Crockett County in Southwest Texas (Figure 1) contains two major producing sands, the Canyon and the Penn. These sands are complex turbidite deposits that are characterized by numerous gas productive members with permeabilities from less than 0.001 mD to over 0.10 mD and are found at depths of 6,000 to 8,000 ft. 1 A recent change in field rules will allow drilling to 40 acres spacing in most parts of the field. Initial development began in the early 1960s on 320 acre spacing, with subsequent infill drilling on 160- and 80 acre spacing. Typical completions require fracture treatments using water based fluids containing 50 to 250 klbs of 20/40 sand to achieve economic production rates. Ultimate gas recoveries range from 200 MMCF to over 2000 MMCF and can vary significantly from well to well. Historically, many wells with multiple pay zones were fracture treated simultaneously, while other wells were fracture treated in isolated stages. Problem. Quantifying the infill potential in the OZONA (Canyon) field is difficult for several reasons: the layered and low permeability nature of the reservoir, the hydraulic fracturing of wells, the variation in well spacing, and the local and regional variations in rock quality. These complicating factors often cloud the extent of depletion, benefits of improved completion and operation techniques, and make the quantification of infill potential rather difficult. Because of these complexities and the fact that our study area contained over 1000 wells, the time and cost requirements of a conventional reservoir engineering study were unacceptable. Instead we applied a new technique that was found to be useful in a large tight gas field in East Texas. 2 History. The OZONA field, located in Crockett County in Southwest Texas (Figure 1) contains two major producing sands, the Canyon and the Penn. These sands are complex turbidite deposits that are characterized by numerous gas productive members with permeabilities from less than 0.001 mD to over 0.10 mD and are found at depths of 6,000 to 8,000 ft. 1 A recent change in field rules will allow drilling to 40 acres spacing in most parts of the field. Initial development began in the early 1960s on 320 acre spacing, with subsequent infill drilling on 160- and 80 acre spacing. Typical completions require fracture treatments using water based fluids containing 50 to 250 klbs of 20/40 sand to achieve economic production rates. Ultimate gas recoveries range from 200 MMCF to over 2000 MMCF and can vary significantly from well to well. Historically, many wells with multiple pay zones were fracture treated simultaneously, while other wells were fracture treated in isolated stages. Problem. Quantifying the infill potential in the OZONA (Canyon) field is difficult for several reasons: the layered and low permeability nature of the reservoir, the hydraulic fracturing of wells, the variation in well spacing, and the local and regional variations in rock quality. These complicating factors often cloud the extent of depletion, benefits of improved completion and operation techniques, and make the quantification of infill potential rather difficult. Because of these complexities and the fact that our study area contained over 1000 wells, the time and cost requirements of a conventional reservoir engineering study were unacceptable. Instead we applied a new technique that was found to be useful in a large tight gas field in East Texas. 2