Water Injection Facilities Research Articles

Analysis of Energy and Exergoeconomic on Water Cleaning and Injection Facilities in the CPP Block, Indonesia

One of the problems in the upstream oil and gas industry is that large quantities of produced water must go through a water cleaning and injection process in accordance with the Regulation of the State Minister of the Environment Number 19 of 2010 of the Republic of Indonesia concerning the quality standards of wastewater for oil and gas and geothermal activities. A total of 224,257.1 barrels of water per day which is produced water in the CPP Block must go through a water management process which requires a large energy consumption of 269.47 MW/month. One effort to reduce the use of electrical energy is to conduct energy and exergy analysis to determine the point of greatest energy use as a result of exergy destruction and convert it into economic costs as operating cost losses. From the research, it is known that the largest electrical energy consumption is at the injection pump 235.47 MW/month with exergy 67.72 KW, the largest exergy destruction is 31.04 KW at the charge filter pump with an efficiency of 54%. Energy and exergy analysis is used to identify changes in energy quality in a system.

Operator Develops Fully Smart Onshore Field

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203461, “Digitalization in the Oil and Gas Industry—A Case Study of a Fully Smart Field in the United Arab Emirates,” by Muhammad Arif and Abdulla Mohammed Al Senani, ADNOC, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9–12 November. The paper has not been peer reviewed. One of the first oil fields in the UAE to be fully operated remotely is in the southeast region, 250 km from Abu Dhabi. The complete paper discusses the development and commissioning of the field, which is the first smart field for ADNOC Onshore. The designed and applied technology facilitated unmanned operation of the field from downhole to export. Introduction Oilfield digitalization encompasses gathering real-time and non-real-time data from wells, flow lines, manifolds, stations, and water injection facilities; analysis of the data using algorithms, flowcharts, plots, and reports; and user access to this data on user-friendly screens. This allows engineers to focus on interpretation of data vs. searching, organizing, and formatting the data. In the bigger picture, the data collected will lead to conclusions and set bases for important decisions for similar projects in the future, enabling a lesson-learning approach to design new oil fields. The accumulated theoretical and practical research results of smart-field implementation require analysis and synthesis to maintain perspective of the entire project. Both were applied in the Mender field, which is the subject of the complete paper. Problem Statement The Mender parent field has been producing since 2013 with minimal digitalization for wellheads. Wells are not fit-ted with remote sensors, and operators have been visiting the wells to collect data using analog gauges. Collected data are stored in computers or as hard copies. Some critical data is lost, which affects decision-making. The new Mender field is 50 km from the parent field and is in a sensitive area close to international borders. The field area is a wildlife reserve for various endangered animals. The nature of operations is highly critical because of concentrations of hydrogen sulfide (H2S) that could jeopardize employees’ health and safety.

Development and Validation of a New Model for In Situ Foam Generation Using Foamer Droplets Injection

Foam generation and transport in porous media are a proven method to improve the sweep efficiency of a flooding fluid in enhanced oil recovery process and increase the effectiveness of a treatment fluid in well intervention procedures. Foam in the porous media is often generated using surfactant alternating gas or co-injection. Although these operations result in good incremental production, the profit losses could be high due to surfactant retention and lack of water injection facilities in the target fields. One way of reducing foam generation operations expenses is by injecting the surfactant solution disperse throughout the gas phase in a process called “disperse foam.” Core-flooding experimental results have shown that disperse foam techniques reduce the surfactant retention and increase cumulative oil production. This increase means that not only the foam is being generated but also it is blocking the high mobility channels and enhancing the sweep efficiency. Additionally, the operational implementation in field operations is very simple and reduces significantly operational costs of the process. Because few laboratory core-flooding tests and field pilots have been executed using the disperse foam technique, there is a high level of uncertainty associated with the method. Besides, the models reported in the literature do not account for all the associated phenomena, including the surfactant droplets transfer between the gas and liquid phases, and the lamellae stability at low water saturation. For this reason, the development of a mechanistic disperse foam model is key to understand the phenomena associated with “disperse foam” operations. In this work, we use a previous foam mechanistic model to develop a disperse foam model that includes the physicochemical mechanisms of the foaming process a core scale. The model accounts for the foamer mass transference between the gas and liquid phases in a non-equilibrium state with a particle interception model, also accounts for the reversible and irreversible surfactant adsorption on the rock surface in dynamic conditions with a first-order kinetic model, and includes foam generation, coalescence and, transport using a population balance mechanistic model.

Process Design of Cyclic Water Flooding by Real-Time Monitoring

The gradual decline in the oil production rate of water flooded reservoirs leads to decrease in the profit of water flooding system. Although cyclic water injection (CWI) was introduced to reduce the descending trend of oil production in water flooded reservoirs, it must be optimized based upon the process parameters. The objective of this study is to develop all process design criteria based upon the real-time monitoring of CWI process in a naturally fractured reservoir having five producing wells and five injector wells completed in an Arab carbonated formation containing light crude oil (API = 42 deg). For this aim, a small pilot oil field was selected with water injection facilities and naturally producing oil wells and all data were collected from the field tests. During a five years' field test, the primary observations at the onset of shutdown periods of the water injection system revealed a repeatable significant enhancement in oil production rate by a factor of plus 5% leading us to assess the application of CWI. This paper represents the significant parameters of pressure and productivity affected during CWI in naturally fractured carbonate reservoirs based upon a dual porosity generalized compositional model. The results hopefully introduce other oil producer companies to the potential of using CWI to increase oil production in conventional water injection systems. The results also outline situations where such applications would be desirable.

Enhancing Offshore Coiled-Tubing Interventions in Difficult Weather Conditions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24693, ’Enhancing the Operational Envelope for Offshore Coiled-Tubing Interventions To Be Performed in Monsoon Season,’ by Reawat Wattanasuwankorn, Franklin Hammer, and Richard Christieson, Halliburton—Boots & Coots, and Yan Song and Nick Long, Brunei Shell Petroleum Company, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Copyright 2014 Offshore Technology Conference. Reproduced by permission. An operator requiring an offshore coiled-tubing (CT) intervention offshore Brunei in the South China Sea encountered challenging monsoon weather conditions as well as limited and aging offshore facilities. Innovative technologies from various applications, including a full-catenary CT system, a dynamic-positioning (DP) vessel, a knuckle-boom crane, and a heave-compensated gangway, were combined to provide the operator with a successful solution for CT-intervention improvement. Introduction Operations were performed in the Darussalam offshore waterflood oil field. The field’s average sea depth was approximately 30 m of water, and the field was approximately 70 km northeast of Seria. A central field complex had living quarters for approximately 160 personnel, gas lift and compression facilities, and water-injection facilities. Waterflooding was a significant factor supporting the hydrocarbon-production levels, and, to increase hydrocarbon production, water-injection improvements were required. During monsoon season, the conventional well-intervention vessel had a limited operating envelope because it was unable to hold in a rough sea position and lacked emergency-disconnect CT and hydraulics-hose systems and a compensated gangway. These limitations made safe operation impossible during monsoon season. Once the operating rate was deemed limited, stimulation (acidizing) activity was postponed, thus affecting production results. However, with new concepts of intervention, the vessel was able to continue operating during rough sea conditions safely and more efficiently.

Startup of Pazflor Giant Offshore Angola Tackles Challenges From Two Reservoirs

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23176, ’Startup of a Giant,’ by Arnaud Constant and Lionel Ramat, Total E&P Angola, prepared for the 2012 Offshore Technology Conference, Houston, 30 April- 3 May. The paper has not been peer reviewed. The Pazflor development includes four reservoirs in Block 17 deep offshore Angola, which produce to a floating production, storage, and offloading (FPSO) unit through one Oligocene subsea loop and three Miocene lines connected to subsea separation units (SSUs) and subsea pumps, with associated-gas and water-injection facilities (Fig. 1). The startup of the Pazflor field required a response to three simultaneous challenges—startup of a large complex facility; flow assurance for two different reservoirs and oil qualities, an Oligocene field with light oil and Miocene fields with heavy viscous oil; and operating innovative Miocene subsea facilities with gas/liquid separation on the seabed. Startup Preparation Manning and Training. Although most of the production personnel were already experienced with FPSO operations, specific attention was given to training and a local training center at the Total E&P Angola offices was maximized. One of Pazflor’s innovations was the design and use of an immersive training simulator (Fig. 2). This simulator was generated from construction of a 3D model and represents all the topside facilities with realistic rendering. In this 3D environment, operators move virtually through a simple interface, allowing for familiarization with their future facilities. Because all equipment is tagged, the operator can easily link his work documents, such as process flow diagrams and piping and instrumentation diagrams, to the actual FPSO environment before its completion or without actually being there. This simulator also can be used to simulate procedures execution, either individually or in a group, thanks to preloaded scenarios. Startup Milestones and Initial Planning. The precommissioning, commissioning, and startup activities were structured according to milestones defined in the early project stage by field operations teams and included in relevant project-packages contracts. This breakdown by startup milestones was taken into account by the commissioning team from the early onshore commissioning stage and was later used to prioritize offshore construction, commissioning, and startup activities during the offshore campaign. Eighteen startup milestones were considered initially, focusing on utilities, oil production, water injection, gas injection, and export systems and covering prestartup, startup, and normal- operations phases. The facilities were split into systems and subsystems, with a total of 669 subsystems, each linked to a specific startup milestone.

Erha Floating Production, Storage, and Offloading Vessel

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18659, "Erha and Erha North Development: Erha Floating Production, Storage, and Offloading Vessel," by S.M. Day and G.J. Parker, ExxonMobil, and P. Barclay and H. Boulais, Saipem, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The new-build Erha floating production, storage, and offloading vessel (FPSO) is one of the largest in the world, at 285 m long by 63 m wide, with a 2.2-million-bbl-capacity hull and capacity for 210,000 B/D oil processing, 340 MMscf/D gas injection, and 150,000 B/D water injection. The full-length paper discusses the development of the FPSO, including design and operational features incorporated to meet field-specific requirements. The paper also addresses the project-management challenges associated with each phase of the job, with emphasis on the safe and timely execution of a sequential drill center startup while managing simultaneous production operations and in-field development drilling. Introduction The Erha and Erha North development, in 1200 m of water approximately 97 km offshore Nigeria, consists of three subsea drill centers tied back to the FPSO by steel catenary risers (SCRs). Injection fluids are transferred from the FPSO by the SCRs and flowlines for subsea injection at the drill centers. The FPSO is a new-build, spread-moored vessel consisting of two trains of three-stage oil separation. Processed crude is stored in the hull and offloaded regularly to tankers through offloading lines and a catenary anchor leg mooring (CALM) buoy. Associated gas is compressed and dehydrated to provide fuel gas, with the remainder reinjected into the producing reservoir. Water injection facilities inject treated seawater into the reservoir for pressure maintenance to enhance oil production. The design, fabrication, integration, and startup of the Erha FPSO was a global undertaking, with engineering performed primarily in France, India, and Nigeria; hull fabrication in Korea; and topside fabrication in Singapore, Malaysia, and Nigeria. The hull and topside were integrated in Singapore, and the FPSO was towed to offshore Nigeria for installation. This work was carried out under a single prime contractor, Saipem S.A., and its in-country affiliate, Saipem Contracting Nigeria Ltd. (SCNL) and included key design and execution interfaces with the Erha tiebacks and subsea-system prime contractors. Facilities Description The Erha FPSO (Fig. 1) is a barge-shaped, new-build monohull with all of the processing equipment on its top deck. It has a 2.2-million-bbl oil-storage capacity. Processed oil is offloaded to export tankers by the CALM buoy offloading system. The FPSO also has the capability to offload crude to tandem moored export tankers in a "bow-to-bow" configuration in the event that the offshore loading system is not available.

The Balmoral, Glamis and Stirling Fields, Block 16/21, UK Central North Sea

Abstract The Balmoral Oilfield is a mature asset in its final phase of production. Associated with the Balmoral development have been the less significant Glamis and Stirling Fields. Each field is different from the perspective of geology and many other issues. Balmoral is a typical Paleocene oilfield with good water drive from a large regional aquifer. Interestingly this was not recognized at the start of the development when water injection facilities were commissioned. Glamis is a smaller field of Late Jurassic age containing somewhat lighter oil than Balmoral. Water injection has been necessary to maximize recovery in this field. Stirling is one of the few fields in the North Sea to produce commercially from the naturally fractured Devonian Sandstone. This field is developed by a single horizontal well. Balmoral oil recovery has significantly exceeded original expectations, whilst Glamis and Stirling have produced as much as expected.

The Brent Field, Block 211/29, UK North Sea

Abstract The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The Brent Field lies entirely within UK licence Block 211/29 at latitude 61°N and longitude 2°E; the adjacent Brent South accumulation extends into Block 3/4A. The water depth is 460 ft. The Brent Field discovery well was drilled in 1971, and was followed by six further exploration and appraisal wells. Seismic data over the Brent Field has been acquired in four separate vintages. The latest acquisition in 1995 allowed detailed mapping of the complex eastern margin of the field for the first time The Brent Field is developed from four fixed platforms (Alpha, Bravo, Charlie, Delta) installed between 1975 and 1978. Production commenced in 1976 and, for the first 22 years of field life, the platforms provided production, water injection and gas injection facilities for both the Brent and Statfjord Formation reservoirs. The Brent South accumulation is produced via the Brent Alpha platform, through sub-sea tie-backs and extended reach wells. In 1992, the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil, extending the field's life by 5-10 years. In January 1998, water injection into the main field was stopped and depressurization of the field initiated. As of January 2000, a total of 220 platform wells and three sub-sea wells (173 producers, 50 water injectors) have been drilled in the Brent Field. The original oil/condensate-in-place is currently estimated at 3.8 MMMSTB, and the estimated original wet gas-in-place is 7.5 TSCF. Total ultimate recovery for all reservoirs is expected to be 1988 MMSTB oil and condensate and 6000 BSCF gas. Cumulative oil and net gas production, as of 1st January 2000, was 1875 MMSTB oil and 4196 BSCF gas This paper summarizes the current understanding of the field based on acquisition of new 3D seismic data, 130 new wells, detailed structural and sedimentological modelling, development of the complex crestal part of the field and finally, the initiation of an extensive brown field re-development project to depressurize the reservoir

Mothballing and Demothballing of an Onshore Oil Field

Summary This paper analyzes recent experience gained after mothballing and demothballing the Bab onshore oil field. It reviews the type and method of protectionlinhibition applied to the wells, flowlines, production and water injection facilities, and other related equipment. The work carried out during shutdown and field recommissioning is discussed along with reservoir engineering aspects, including the monitoring program and performance review. The method used to check the tubing integrity also is addressed. The impact and consequences of mothballing an onshore oil production field are presented, together with the findings and work done to recommission the field. The paper discusses the procedures used to protect the field facilities to minimize equipment deterioration and to optimize the cost of mothballing. The time required to recommission the field also is discussed.

The Brent Field, Block 211/29, UK North Sea

Abstract The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The field lies entirely within UK licence Block 211/29 at latitude 61°N and longitude 2°E. The water depth is 460 ft. The discovery well was drilled in 1971, and six further exploration and appraisal wells were drilled. Seismic data over the Brent Field has been acquired in three separate vintages. The latest acquisition is a 3-D grid recorded in 1986. Reprocessing of the entire 1986 3-D seismic data set was initiated in 1989. The original oil/condensate-in-place, estimated on 1/1/89, is 3500 MMBBL, and the estimated original wet gas-in-place is 6700 TCF. Oil production is now in the decline phase. Average production in 1988 was 334,000 BOPD, with gas sales remaining at the plateau rate of 500 MMSCFD. The field is being developed from four fixed platforms, each providing production, water injection and gas injection facilities for both Brent and Statfjord Formation reservoirs. Gas injection is distributed to achieve an intermediate oil rim development in some reservoir units. The platforms were installed between 1975 and 1978. Production commenced in 1976. The slump faulted crestal areas of both reservoirs have yet to be developed. These crestal areas contain about 5% of the recoverable reserves. Appraisal drilling was carried out in the crest during 1988 and 1989. The Brent Field is located approximately 100 miles north-east of the Shetland Islands and 300 miles NNE of Aberdeen (Fig. 1). The discovery well location is at latitude 61°05'53.87" North longitude 1°41'30.H" East. The water depth is 460 ft The field comprises two distinct reservoirs, the Brent Group and the Statfjord Formation, which are of Middle Jurassic and Lower Jurassic/Triassic age respectively. The reservoirs occur in a westerly dipping tilted fault block in a fault controlled unconformity trap (Fig. 2). The size of the hydrocarbon bearing area is approximately 10 miles from north to south and 3 miles from east to west (Fig. 3). The reservoirs are in turn divided into seven separate reservoir units; four cycles in the Brent Group reservoir and three units in the Statfjord Formation reservoir. Laterally two major east-west orientated faults divide the field into three separate production areas. A fourth area is the north-south orientated crestal part of both reservoirs, which is faulted and has a series of down faulted slump blocks overlain by 'Reworked Sediment'. This area still has to be developed. The Shell/Esso joint venture North Sea oilfields are named after water and waterside birds. The Brent Field is named after the Brent goose.

Constructability improvement of Project Designs

A case study is described to show how the application of constructability concepts can contribute substantially to the success of a project. Constructability is defined as the optimum use of construction knowledge and expertise in the conceptual planning, detail engineering, procurement, and field operations phases to achieve the overall project objectives. The Construction Industry Institute (CII) has developed and formalized generic concepts of constructability. Seven constructability concepts applicable to the engineering and procurement phases are set forth. In the case study, constructability concepts similar to those recommended by the CII were implemented as a means for resolving several construction problems encountered on a water injection facilities project valued at $45 million. The cost of the constructability program was approximately $2 million. The cost of attempting to build the original design was forecasted to be several times higher than the cost of the constructability improvement program. The constructability improvment program is believed to have saved both the owner and the contractor some anticipated legal disputes.

Suspended Solids Specifications for Water Injection From Coreflood Tests

Summary A method based on the results of laboratory coreflood tests is proposed for predicting the injectivity decline rate of water injectors. The aim of this method is to provide design specifications for water treatment and injection facilities and procedures with which well injectivity behavior can be analyzed. To illustrate the results that can be obtained with the proposed method, data from coreflood tests are used to construct injectivity-decline-rate curves for an arbitrary injection well.

Tazerka Multiwell FPSU: Design of Production Facilities Integrated With the Tanker

Summary This paper will review the design of the production facilities on the multiwell floating production and storage unit (FPSU) operated by Shell Tunirex in the Tazerka field, offshore Tunisia, on behalf of a joint venture with AGIP (Africa) and Entreprise Tunisienne d'Activits Petrolires. Economics and product specification dictated the application of special techniques in the production and utility designs regarding process flexibility, gas disposal, power generation, and pollution prevention. The field, containing estimated reserves of 8 to 10 million bbl [1.3 × 10(6) to 1.6 × 10(6) m3] of recoverable oil, is located in deep water (459 to 984 ft [140 to 300 m]). It was desirable to use a single-process train with as near a 100% on-stream factor as possible. While this is not the first application of a flow station on a weathervaning unit, it is believed to be the first to process crude directly from several subsea wells. Introduction The Tazerka field lies 35 miles [56 km] offshore the northeast coast of Tunisia in the Hammamet Grand Fonds permit. It has been in production since Nov. 1982 and currently produces some 10,000 B/D [1590 m3/d]. Oil is produced from four subsea completed wells in water depths ranging from 459 to 607 ft [140 to 185 m], flowing by Coflexip (TM) flowlines to the single anchor leg system (SALS) that holds the FPSU on location in 459-ft [140-m] water depth. Oil flows through swivels on the SALS to the FPSU-i.e, to the converted very large crude carrier (VLCC) tanker Murex (Fig. 1). The entire crude production facilities are integrated onto the converted unit, which then stores up to 140,000 tonnes [140,000 Mg] of crude. The system is completely independent of platforms and pipelines to shore, with off-take achieved by discharging, using the original VLCC cargo pumps, to trading tankers moored alongside. This approach to developing the field, instead of conventional methods such as steel or concrete platforms connected by pipeline to shore, was dictated by economics, which showed that conventional methods would have been too expensive. Facilities Description The initial field development plan called for reservoir natural depletion with provisions for future installation of water injection and gas lift facilities to enhance recovery. Fig. 2 shows a block flow diagram depicting the deck-mounted facilities/utilities that have been designed and engineered for the Tazerka FPSU. Crude Oil Production The Tazerka FPSU development is designed to receive 30,000 B/D [4770 m3/d] of produced liquids from up to eight subsea completed wells. All wells have provisions for future gas lifting. Three of these wells also have been designated for water injection. At present, the well fluids from the four installed subsea wells flow through 4-in. [10-cm] Coflexip seabed lines to the SALS manifold, then through a six-bore product swivel, and finally, through the mooring yoke to the receiving manifold on the FPSU. Well subsurface safety valves and wing valves are controlled hydraulically from a control panel on the FPSU deck by control lines routed through a 20-bore swivel on the SALS. Oil/Gas/Water Separation From the receiving manifold on the FPSU, the incoming stream is routed to a single-process train, consisting of a separation unit (HP, LP, and test) and a stabilizing unit. The possible combinations of the process train and the valve switching provide for an on-stream factor close to 100%. Oil can be produced through any one of the six product swivels to the receiving manifold. All separators are of identical design and are capable of handling the full production flow, therefore enabling any one separator to be out of service for maintenance or repair while still maintaining production through the others. The test separator also can be used as a stabilizer. Fig. 3 shows the changeover philosophy in detail. Produced water can be removed from the crude oil in two stages.1. Bulk separation in the three-phase separators ispossible in either series mode or parallel mode.2. Final separation of water occurs in the FPSU's dedicated crudereceiving tanks, where water can be taken off the bottom by theoriginal VLCC's stripping pumps. A dehydrator can be installed ifhigh water production or stable emulsions occur. JPT P. 1091^

The Secondary Recovery Project at Ogharefe Field, Nigeria

A secondary recovery project involving water injection and gas-lift facilities was installed in the Ogharefe field in 1979 following detailed reservoir simulation studies. Two years' operation provides the opportunity to discuss the progress of the project so far.

East Rainbow Supervisory Control System

Abstract Mobil Oil Canada, Ltd. has installed a solid-state Supervisory Control System to operate its producing facilities 20 miles east of Rainbow Lake in northern Alberta. The system utilizes a small computer, located at the main battery in the center of the oilfield. as its nucleus. Through the medium of logic programmed into the computer the functions of alarm monitoring, data gathering, direct control and report preparation are exercised over twenty one oilwells and various water and gas injection facilities. This paper describes the design and operation of this Supervisory System. It also reviews the performance of the various equipment since its installation in August 1970. Introduction THE EAST RAINBOW AREA, located 400 miles north of Edmonton, is a geographic extension of the main Rainbow oilfields in the general Rainbow Lake area of northern Alberta. Mobil Oil Canada drilled its first successful well in East Rainbow during the summer of 1965. Today, it produces an average of 15,000 barrels per day from twenty-one wells in eighteen separate pools; 90 per cent of this production is from the Middle Devonian Keg River Formation. Four satellites located about the field serve to funnel the oil through flowlines to the central Battery 10 complex (Figure 1). This complex consists of the main central treating station, a water injection plant, a produced water disposal station and two 800-hp gas conservation compressors. An aerial view of these facilities is sho1rvn in Figure 2. Pressure maintenance is carried out by injecting water into seven pools and the produced gas into one pool. A Supervisory Control System for Mobil's East Rainbow properties was first proposed in the summer of 1968. Its intended purpose: to minimize operating manpower in this remote area by placing the Battery 10 complex and the four satellites under the continuous supervision of a computer. A secondary intention was to have this system serve as a possible prototype for future :Mobil automation projects in the far north and offshore areas. The availability and/or reliability of communication links in these areas, particularly in the early stages of an oilfield's development is often a deciding factor when considering the attractiveness of automation investments. It was recognized early in the project that to properly satisfy the proposed objectives of the System, a small digital computer would be required in the field. During the winter of 1969–70, the end devices needed under an automated production scheme were installed throughout the field, and with the delivery of the Supervisory System hardware in August 1970, the over all System first became operational in September of last year. After the initial start-up and debugging problems were dispensed 'with, the performance of the Supervisor System, specifically the computer, has lived up to its original expectations. In the process, the concept of placing a computer in the oilfield has been shown to be entirely feasible. Ultimately, the computer will calculate the individual pool allowables and automatically adjust the well chokes as required.

Performance of the Lower Pawelek Reservoir, Falls City Field, Karnes County, Texas

Abstract This paper presents the initial results of a pressure maintenance by waterreturn project in the Lower Pawelek reservoir of the Falls City Field, KarnesCounty, Southwest Texas. Production is from the Lower Wilcox section at anaverage depth of 6,030'Ft on the downthrown side of a "down to thecoast" fault. Of particular interest is that the reservoir oil is highgravity and low viscosity but far undersaturated with gas at the originalreservoir pressure and temperature. The early pressure and production historyindicated only a partial or limited water drive, and this fact, coupled withthe characteristics of the reservoir fluid and artificial lifting problems, made advisable the water injection program to maintain reservoirpressure. The paper includes a description of the reservoir and reservoir fluids, thepressure and production history, a description of the water injectionfacilities, and the results of reservoir calculations involving Hurst'sunsteady state flow and the material balance equations for calculation of waterinflux and prediction of the pressure-production relationship at various ratesof withdrawal. The reservoir calculations and initial field results indicate that reservoirpressures in excess of 85 per cent of original pressure can be maintained bycontrol of water injection even at very high rates of production. Introduction The purpose of this paper is to report the initial results of a pressuremaintenance by water return program in the Lower Pawelek reservoir, Falls CityField, Karnes County, Texas, and to calculate an empirical relationship betweenpressure and production in this limited or partial water drive reservoir. Discussion Location The Falls City Field (Fig. 1) is located two miles north of the town of FallsCity in Karnes County, Texas, and is approximately 50 miles south-southeast ofSan Antonio on U. S. Highway 181. Discovery and Development The initial block of leases was taken after a surface geological surveyidentified a major east-west fault and closure on the south or downthrownsection. The discovery well, Southern Minerals Corporation's Joe F. Bartosch 1, was completed at 4,650'Ft in the Lower Bartosch sand in December, 1944.Drilling was continuous until December, 1946, and resulted in the discovery of12 oil reservoirs between 4,600 and 6,050'Ft in the Middle and Lower Wilcoxformations. T.P. 2937