Shut-in Well Research Articles

Transient Fluid and Heat Flow Modeling in Coupled Wellbore/Reservoir Systems

Summary This paper presents a transient wellbore simulator coupled with a semianalytic temperature model for computing wellbore-fluid-temperature profiles in flowing and shut-in wells. Either an analytic or a numeric reservoir model can be combined with the transient wellbore model for rapid computations of pressure, temperature, and velocity. We verified the simulator with transient data from gas and oil wells, where both surface and downhole data were available. The accuracy of the heat-transfer calculations improved with a variable-earth-temperature model and a newly developed numerical-differentiation scheme. This approach improved the calculated wellbore fluid-temperature profile, which, in turn, increased the accuracy of pressure calculations at both bottomhole and wellhead. The proposed simulator accurately mimics afterflow during surface shut-in by computing the velocity profile at each timestep and its consequent impact on temperature and density profiles in the wellbore. Surrounding formation temperature is updated in every timestep to account for changes in heat-transfer rate between the hotter wellbore fluid and the cooler formation. The optional hybrid numerical-differentiation routine removes the limitations imposed by the constant relaxation-parameter assumption used in previous analytic-temperature models. Both forward and reverse simulations are feasible. Forward simulations entail computing pressure, temperature, and velocity profiles at each wellbore node to allow matching field data gathered at any point in the wellbore. In contrast, reverse simulation allows translating pressures from one point to another in the wellbore, such as wellhead to bottomhole condition.

Well Test Analysis in the New Economy

Abstract This paper provides a chronological history of the evolution of advancement in well testing techniques in order to examine how the technology has progressed to its present state. The first factors examined are those that strongly influenced technological development in well-test analysis. The next discussion concerns the problems that still require resolution, and finally, the authors will present what they envision for the future of well-test analysis. Introduction The origin of fluid flow through porous media may be traced back to the experiments run by Darcy during the 19th century to investigate the flow of water, a Newtonian fluid, through a bed of unconsolidated sand filter. This sand filter probably had a fairly high permeability. Darcy's equation was developed and became the basis for significant further development. It was not a great surprise to find that the equations governing flow of a Newtonian fluid in high permeability formations under laminar conditions are identical to those that govern heat flow in solids. The original idea of analyzing pressure vs. time data from a producing or shut-in well to obtain information on the producing stratum first appeared in the field of hydrology. Hydrologists were mainly interested in the behaviour of underground water flow in large aquifers. Shortly thereafter, The is(1) published his work on fluid flow in porous media, which included his point-source solution. Muscat(2) was probably the first to study a problem relating to oil reservoirs-the eventual static pressure behaviour of a shut-in well in a closed oil reservoir. When compared to the initial reservoir pressure, this new static pressure can be used to measure the quantity of hydrocarbons produced up to the time of the test. The need for reliable quantitative analysis has primarily been driven by economics since accurate formation permeability determination is needed for forecasting reservoir production. Initial reservoir pressure and drainage boundaries provide the information needed to determine the amount of hydrocarbon in place. However, determination of well condition (i.e., skin factor) is also necessary to predict how much expenditure will be needed to improve productivity. Since Muscat, literally thousands of papers have been published on the analysis of pressure tests. Numerous new tests have been devised to determine specific reservoir parameters. This explosion in literature was basically due to the ease by which pressure behaviour could be measured and the enormous value of the parameters calculated from these tests. In addition to the information mentioned, pressure tests can be used to estimate:How efficiently a well is completed;The need for and anticipated success of a stimulation treatment;The general type of well treatment desired; and,The degree of connectivity of one well to another. Modern well-test analysis started when Horner(3) and Miller et al.(4) presented their famous papers where semi-log straight lineswere introduced as the first technique for analyzing pressure tests. Within a few years, Van Everdingen and Hurst(5) and Moore et al.(6) introduced other fundamental developments with the concept of wellbore storage.

Buildup Solution in a System With Multiple Wells Producing at Constant Wellbore Pressures

Summary This paper presents a new analytical solution to obtain the shut-in wellbore pressure at a vertical well that had been producing at a constant wellbore hole pressure from a closed-boundary reservoir with multiple wells producing at constant, different wellbore pressures. The analytical solution is a set of coupled simultaneous equations in the Laplace space (one for each well). These are obtained by using separation of variables, Green's functions, and the unit-step function with the methods of Rodriguez and Cinco-Ley1 and Camacho-V. et al.2 The equation for the shut-in well is nonlinear, preventing us from obtaining the formal solution of the set of equations either in real time or in Laplace space. A number of approaches were used to make the solution tractable. These included expansion of Green's function for large times, a Taylor series expansion of the rates around the time of shut-in, and application of the concepts of Najurieta.3 None of the approaches gave satisfactory results.

Streamline Technology: Reservoir History Matching and Forecasting = Its Success, Limitations, and Future

Although reservoir flow simulation is a mature technology, there is a general lack of understanding in the oil and gas industry as to when it should be applied, the limitations of it and how recent technical improvements have changed simulation. Streamline models have dramatically changed simulation work and made predictions better. Simple workflow and quality control issues are absolutely critical to insuring reasonable forecasts. There are various technologies that will substantially improve simulation forecasts and reduce error bars. Some of these new technologies are:Streamline based flow simulationAssisted history matching (AHM) techniquesFour dimensional seismic (time lapse 3D seismic)Parallel computingIntegrating flow simulation with geo-mechanical effects. This article focuses primarily on the first two points. Streamline Based Flow Simulation Streamtube and streamline technology, to a large extent, have been driven by the realization that heterogeneity controls recovery factors for many fields. This realization caused the derivation of more complex geological models, but unfortunately also highlighted the gap between geological detail and simulation capability. Streamtube technology was originally developed in the 1960s(1, 2). Two dimensional streamtube models were initially available for homogeneous permeability regular flow patterns, such as a five-spot pattern. Streamtube models were later generated for irregular well positions and areally heterogeneous reservoirs. Old streamtube models only allowed constant well rates and positions (i.e., no infill wells, no rate changes or the shutin of wells were allowed). Gravity effects, and therefore the vertical sweep efficiency were not always accounted for. Thus, streamtube modelling often could not allow for infill drilling or shutin wells, and streamlines were fixed in space. As a result of these limitations such early applications were limited and basically evaluated only the areal sweep efficiency of a pattern. To account for vertical sweep efficiency, Chevron(3) developed two-step hybrid streamtube models in which vertical cross sections were first simulated and then combined with areal streamtube models(4-6). Thus, vertical sweep, then areal sweep, were evaluated. However, infill drilling and large changes in production/injection rates meant that streamtube geometry changed resulting in limitations with this technique. Streamline technology is now practical in many field cases because it includes:Gravity3D effectsChanging well conditionsMultiphase flow. Streamline technology includes gravity effects and allows well rate changes (starting/stopping of wells)(7–11). This allows engineers to perform a one-step process that evaluates both vertical and areal sweep, and also accounts for well changes. There has been an explosion of studies that have highlighted the usefulness of streamlines(12-19). In many field situations gravity and vertical heterogeneity are important parameters for waterflood recovery. How Is Streamline Technology Different From Finite Difference Simulation? In a conventional finite difference simulation, there is a pressure-solve segment and a transport-solve (saturation) segment. In finite difference we solve for pressure then calculate flow based on the pressure distribution (for IMPES solutions), but flow transport is from block to block, whereas, in a streamline/streamtube simulation model, fluids are transported along streamlines, as shown in Figure

Evaluation of Attic Oil Recovery Schemes For the Fenn West Leduc D-3E Reef Reservoir

Abstract Reservoir simulation was employed to evaluate various attics oil recovery schemes for the Fenn West Leduc D-3E reef reservoir. Based on geological and seismic data, a three-dimensional reservoir model was constructed to represent the pinnacle-reef reservoir and the adjoining bottom aquifer. The reservoir model was calibrated by history matching the production performance of the two vertical wells in the pool. Model calibration results indicated that water production from the pool is mainly attributable to a rising oil-water contact in the reservoir. Furthermore, the current oil production from the pool results from a reverse oil coning mechanism in the attic portion of the reef. Various attic oil production schemes were investigated, including increased liquid withdrawals, reactivation of a shut-in vertical well and horizontal well production from the structurally highest location in the pool. Prediction results indicated that these attic oil production schemes will not recover any significant incremental oil reserves from the pool, but will shorten the remaining producing life of the pool by five to 21 years. Introduction The Fenn West Leduc D-3E pool, located in Township 36, Range 21, West of the Fourth Meridian (Figure 1), is a pinnacle reef reservoir containing light gravity oil (34 °API). Discovery well 08-11-36-21 W4M commenced production from the pool in January 1983, at an initial oil rate of over 300 m3/d (Figure 2). After producing clean oil for over four years, a series of well recompletions was conducted to arrest the increasing water production from the well (Figure 2). In September 1991, the well was suspended due to a high watercut of about 98%. Another well, located at 07-11-36-21 W4M, commenced production in December 1985. The well produced clean oil for over three years and is currently producing at an oil rate of about 12 m3/d and a watercut of about 86% (Figure 3). A third well, located at 09-11-36-21 W4M, previously produced from the Nisku Formation and was converted to a water disposal well in 1987 (Figure 1). Based on pool pressure and production data, the main recovery mechanism in the pool is an active bottom water drive. To April 1992, about 483,500 m3 of oil, 262,900 m3 of water and 38,600,000 m3 of gas have been produced from the pool. Based on data from the Energy Resources Conservation Board (ERCB)(1), the volumetric estimate of original oil-in-place (OOIP) for the pool is about 1,480,000 m3. Correspondingly, the current oil recovery is about 33% of the OOIP. The objective of this study was to evaluate various attic oil recovery schemes for the pool including increased pumping rate for well 07–11, reactivation of well 08–11 and horizontal well production from the structurally highest location in the reservoir. FIGURE 1: Pool location map: Fenn West Leduc. D-3E pool. (Available in full paper) Geology The Fenn West Leduc D-3E pool is extensively dolomitized, resulting in a very high quality reservoir. The average porosity is about 6% and the average horizontal permeability is in the order of several Darcies.

Water-Alternating-Steam Process Improves Project Economics at West Coalinga Field

Summary The water-alternating-steam process (WASP) was applied to vertical expansion (VE) sands in the pilot area of Section 13D, West Coalinga field to stop wasteful steam production and to improve vertical conformance of injected steam. Before the WASP application, steam breakthrough in the VE sands caused well sanding, cutting of downhole tubulars, and high-temperature-fluid handling problems. To alleviate these problems, pumps had to be raised in five wells and one well had to be shut in, reducing oil production from the VE sands and the lower waterflooded zones. A WASP field test, based on a numerical simulation study, was implemented in July 1988 with alternating slugs of water and steam, each injected over 4 months. The WASP eliminated steam production, allowing the pumps to be lowered and the one shut-in well to return to production. Oil production remained constant through the first WASP cycle and increased during the second cycle. Sales oil (total production minus oil used to generate steam) increased as a result of saving generator fuel during the water leg of each WASP cycle, resulting in improved project economics.

Revitalization Of The Pembina

Abstract Over the past eight years, 1981 to mid-989, Canadian Occidental has invested $16,300,000 in the revitalization of the company's Pembina properties. A total of$3,800,000 was invested in 83 fracture stimulations yielding an average payout period of just over one year and incremental reserves per job of 2130 m3. The stimulated wells are currently producing 45 m3/day of incremental oil yielding $1,650,000/year of additional revenue/or the Pembina operation. A total of $12,500,000 was invested in 33 infill wells and their associated facilities. The infill wells have an average payout period of 2.5 years and the estimated incremental reserves per well of 10 930 m3. The infill wells are currently producing 80 m3/day of incremental oil yielding $2,000,000/year of additional revenue. Canadian Occidental's program has increased the current annual revenue to $5,550,000 from an estimated $1,900,000 if none of the work had been Carried out. The increase is significant considering the majority of the work has achieved payout. The work carried out by Canadian Occidental ensures continued profitability and life from the field in the future. Introduction The main purpose of this paper is to prove to the industry that the Pembina Oilfield can be a source of significant reserves and revenue in the future. Huge gains in productivity cannot be expected but sustained economic development can take advantage of the already existing infrastructure with excellent returns in both production and profit. Cities-Service/Canadian Occidental has been active in the Pembina Oilfield since 1956 and was instrumental in setting up many of the units in the field. The company's first waterfloods were initiated in 1961. The company also experimented with gas/LPG injection in both Bear Lake and Keystone. By 1965, most of the Pembina Cardium had been unitized and the majority was under waterflood. Canadian Occidental currently operates 412 wells in the field with 15 batteries and 76 satellites and one gas plant located in Keystone, Of the 412 wells, 282 are producing, 65 are injectors and 65 wells are shut-in. Production from the field, on a Lease Gross Basis, currently averages 420 m3/day of oil, 112 103/m3day of gas, and 1850 m3/day of water as of November 30, 1989. Production on a per producing well basis averages of 1.5 m3/day of oil, 0.4 l03m3/day of gas, and 6.6 m3/day of water. The average producing well operating cost, including battery, shut-in well and injector costs, currently averages $28,800/year. Using a price of $120/m3, the break-even production rate for a Pembina well is 0.7 m3, /day. Over-all, the field is still profitable, but every means had to be taken to increase production. Because the operating cost is not directly proportional to production rates, a 50% increase in production may only equate to a 10% increase in operating costs. Canadian Occidental's Engineering staff in Drayton Valley used the following criteria when choosing fracture stimulation candidates. Explanations into what was looked for in each criteria is also included.

Well Testing In Alberta — 1990s Style

Abstract This paper presents the highlights of a new guide for well pressure and deliverability testing in Alberta. The guide was developed by a joint Industry-ERCB committee to reduce test costs, improve test quality, and clarify testing regulations. New requirements define quality pressure survey methods, and the minimum number of tests that should be run for prudent reservoir management. Relief from testing is provided for advanced depletion, small reserves, low permeability, heavy oil, low productivity, and reduced spacing. In addition, testing costs are reduced by accepting pressures from shut-in wells, acoustic methods, and drill-stem tests, under certain conditions. Operators can choose the type of deliverability test they run: single- vs multi-point. Tests can be scheduled to optimize field operations. The new well testing environment for the 1990s should become less regulated but this requires that the operating industry be committed to quality testing in accordance with the new guide. The industry, the ERCB, and the public stand to gain from this new approach to data gathering. Introduction In 1989, it cost over $250 million dollars to run pressure and deliverability tests for Alberta's oil and gas wells. This cost is expected to increase significantly, throughout the 1990s, as more wells are needed to supply existing and new markets for oil and gas. The time has come to ensure that we get the most from future testing dollars by carefully examining our data needs and test procedures. The Energy Resources Conservation Board (ERCB) has a mandate(1) to provide for the gathering and dissemination of information regarding the energy resources of Alberta. Accordingly, it developed regulations(2), as early as 1961, for the taking and reporting of well tests. The purpose of these regulations is to ensure adequate quality pressure and deliverability data, for use in engineering and economic studies of Alberta's oil and gas pools. Over the years, these regulations were revised a number of times in response to the changing needs of the ERCB, and the operating industry. In 1987, a joint Industry-ERCB technical committee (the committee) was formed to review the ERCB's well testing regulations. The review has resulted in the development of a new guide for well testing(3). A draft of the new guide was distributed to several industry associations: IPAC, CPA, SEPAC, and CIM, for their comments. Their responses suggest that the guide was well received but that further effort is needed to clarify its contents. The ERCB decided to release a first edition of the guide in the second quarter of 1990. This was done to give both the ERCB and the industry an opportunity to work with the revised requirements, and benefit from them without delay. The ERCB has asked the committee for a review of well testing under the new guide in mid-1991. Any problems encountered can be addressed in a second edition of the guide. Assuming no major problems remain, the ERCB will formally adopt the second edition or the guide as part of its regulations.

Stratigraphic Pinchout Traps: Large Hackberry Lower Reservoir in Port Acres Field, Texas

Port Acres gas field is located on the upper Texas Gulf Coast on the east side of the Houston Salt basin. The principal producing zone in the field is the Hackberry Lower reservoir, with a cumulative production of 308 Bcf; the Hackberry Lower ranks 35th in productivity among gas reservoirs in the Texas Gulf Coastal Plain Province. Although the Hackberry Lower reservoir is a candidate for coproduction, secondary recovery has been hindered by difficulties with brine disposal. The reservoir has been abandoned since 1978 except for one shut-in well. Port Acres field lies within a submarine fan complex at the western edge of the Hackberry embayment, which contains strata equivalent to the Oligocene middle Frio Formation. From core data, log patterns, and sand-body geometry, the Lower Hackberry reservoir is interpreted to be a dip-oriented submarine canyon and fan system containing incised channel-fill sandstones and upward-fining sandstones interpreted as intermediate suprafan deposits. Growth fault systems and salt-related structures are abundant in the Port Acres field area. The field discovery well was drilled into a fault-bounded structural trap identified on seismic sections, but the true stratigraphic nature of the trap was identified much later. Stratigraphic pinchouts, common in submarine-fan reservoirs, compartmentalize reservoir-qualitymore » sandstones and can be identified through depositional and structural analysis. In modern exploration practice, integrated studies of reservoir stratigraphy using depositional systems analysis, paleontologic data, 3-D seismic data, and interpretations of the time of emplacement and the geometry of salt structures may be used to identify subtle Gulf Coast stratigraphic traps.« less

High Grading Fracture Candidate Selection

Abstract The ability to choose the best possible fracture stimulation candidate is very important in order to maximize production and revenue, To compare wells consistently in a given area, pressure build-up techniques are utilized. An up-lo-dale isobaric map is required. An estimate of the slope m of all the wells in the area is then determined using known m's from build-up and Jail-off tests. Since Pr and m are given/or all the wells, build-up calculations can be done to determine skin factors and maximum anticipated low rates with a −4 skin factor. Once maximum rates for oil have been estimated the wells with the greatest variance between actual oil production and estimated −4 skin oil production are investigated further to determine the best fracture candidates. Introduction The following paper outlines a method for high-grading fracture candidate selection in mature waterfloods, with medium to low permeability and pressures above the bubble point, by the use of pressure build-up surveys and injection well fall-off tests. The area investigated is the Pembina Easyford Cardium Unit No.1 located 15 km northwest of Drayton Valley. The unit is operated by Canadian Occidental and consists of 15 water injection wells, 78 producing wells and 15 shut-in wells. To fulfill Energy Resources Conservation Board's (ERCB) requirements, an extensive pressure build-up program was conducted from September to December 1986. In all, 17 wells were placed on build-up. To complement the pressure build-upsurvey all 15 water injection wells had fall-off tests conducted on them. In addition, three shut-in wells had injection fall-off tests performed on them (Fig. 1). The high-grading method calculates the present skin factor and then calculates the stabilized production rate at a skin = −4 for all the producing and shut-in wells within the unit. The method depends on assigned values of Pr, derived from the build-up surveys, fall-off tests and static gradients, and the Horner slope m for each well. The criteria and limitations will be discussed in a following section. The final step in the high-grading method compares the actual present oil production rate for each well with the estimated stabilized production rate at a S = −4. The wells with the greatest increase in oil production rates are the wells which should be investigated as potential fracture stimulation candidates. It should be emphasized that the method is only a screening method for determining the best possible fracture stimulation candidates. Once a short list has been generated, other criteria such as WOR, decline rate, peak fluid production rate, remaining recoverable reserves, well recovery and fracture stimulation history can be used to determine the best candidates for fracture stimulation. Equations The following equations were used in the skin and stabilized rate calculations on all of the producing and shut-in wells in Easyford. Equation (Available In Full Paper) The actual reservoir conditions behave in between both cases. The constant was calculated by using the stabilized rate equation and setting q5=q0 and S equal to the calculated present skin factor equation.

Present Thermal State of Western Canada Sedimentary Basin: ABSTRACT

The regional geothermal pattern of Western Canada sedimentary basin was studied using available temperature data from shut-in wells. Average heat conductivity was estimated with net-rock data from Canadian Stratigraphic Services. These data allowed heat flow estimations. The geothermal gradient and heat-flow values for the basin are exceptionally high in comparison with the other Precambrian platform areas, especially in the northwestern part of the Prairies basin in Alberta and British Columbia and most of southern Saskatchewan. Low-gradient areas are found close to the eastern limit of the Disturbed belt of Alberta and British Columbia. Neither the analysis of regional conductivity nor heat generation of the basement rocks based on U, Th, and K data after Burwash explains the heat-flow patterns. Certain hydrogeologic phenomena do suggest the significant influence of fluid flow on geothermal features. Low geothermal gradient areas coincide with water recharge and high hydraulic head regions. The phenomenon of upward water movement in the deep strata and downward fluid flow through much of the Cenozoic and Mesozoic strata seems to be the main influence on heat distribution in the basin. Analyses of coal metamorphism in the upper and middle Mesozoic formations of the Foothills belt and in the central Prairies basin suggest that pre-Laramide heat-flow distribution was different from the present. It is very probable that the Foothills belt had a higher geothermal gradient than the central part of the Prairies basin, opposite to the present relation. End_of_Article - Last_Page 1362------------

Present Thermal State of Western Canada Sedimentary Basin: ABSTRACT

The regional geothermal pattern of Western Canada sedimentary basin was studied using available temperature data from shut-in wells. Average heat conductivity was estimated with net-rock data from Canadian Stratigraphic Services. These data allowed heat flow estimations. The geothermal gradient and heat-flow values for the basin are exceptionally high in comparison with the other Precambrian platform areas, especially in the northwestern part of the Prairies basin in Alberta and British Columbia and most of southern Saskatchewan. Low-gradient areas are found close to the eastern limit of the Disturbed belt of Alberta and British Columbia. Neither the analysis of regional conductivity nor heat generation of the basement rocks based on U, Th, and K data after Burwash explains the heat-flow patterns. Certain hydrogeologic phenomena do suggest the significant influence of fluid flow on geothermal features. Low geothermal gradient areas coincide with water recharge and high hydraulic head regions. The phenomenon of upward water movement in the deep strata and downward fluid flow through much of the Cenozoic and Mesozoic strata seems to be the main influence on heat distribution in the basin. Analyses of coal metamorphism in the upper and middle Mesozoic formations of the Foothills belt and in the central Prairies basin suggest that pre-Laramide heat-flow distribution was different from the present. It is very probable that the Foothills belt had a higher geothermal gradient than the central part of the Prairies basin, opposite to the present relation. End_of_Article - Last_Page 1362------------

Instrumentation Requirements for Kick Detection in Deep Water

In deepwater drilling, increased emphasis must be placed on early kick detection. Using a recently developed computer program to model kicking wells, various types of kick detection instruments were evaluated to determine which are most useful and what sensitivities are desirable. Kick detection based on return-mud flow rate was found most beneficial. Introduction In offshore drilling operations, increasing water depth reduces the difference between the mud weight required to balance formation pore pressures and that weight causing formation fracture. Fig. 1 illustrates this point at the seat of a 3,500-ft (1070-m) surface casing string. The formation pore pressure gradient is assumed to be that of seawater, equivalent to an 8.5-lbm/gal (1020-kg/m3) mud weight. The casing-seat formation fracture gradient at zero water depth (i.e., on land) is assumed to be equivalent to a mud weight of 13.5 lbm/gal (1620 kg/m3) . Translating the same geological conditions to an offshore environment results in the situation shown in Fig. 1. The pore pressure gradient remains constant since the added overburden is seawater; however, the casing-seat fracture gradient decreases dramatically with water depth. If a 0.5-lbm/gal (60-kg/m3) margin is maintained relative to both the fracture and pore pressure gradients, the range of allowable mud weights is reduced substantially as water depth increases.Another way of illustrating the effect of increasing water depth is to consider the "critical kick size." This is the maximum gas influx volume that can be contained in a shut-in well without fracturing the rock at the casing seat. Influxes larger than this will cause an underground blowout if shut in. Fig. 2 shows the critical kick size as a function of water depth for kicks taken while drilling a 12 1/4-in. (311-mm) hole 5,000 ft (1520 m) below a 3,500-ft (1070-m) surface casing string. The drillstring consists of 5-in. (127-mm) drillpipe with 600 ft (180 m) of 8-in. (203-mm) drill collars. The gas is assumed to be a single bubble at the bottom of the hole. Mud weights of 9.5 and 10 lbm/gal (1140 and 1200 kg/m3) and underbalance conditions of 0.25 and 0.5 Ibm/gal (30 and 60 kg/m3) are considered. While kicks of 150 to 250 bbl (24 to 40 m3) are necessary to produce casing-seat failure on land, in 5,000 ft (1520 m) water, the critical kick size is reduced significantly.While there are numerous reasons for limiting kick size on land or in shallow water, this analysis shows that there is increased incentive in deepwater drilling operations to detect and control kicks at an early stage. The accuracy, sensitivity, and reliability of the drilling instrumentation are key elements for determining at what stage a kick will be detected and controlled by the drilling personnel. We have investigated the time-dependent evolution of kicks under a variety of assumed conditions to define better what instruments are useful for early kick detection and what levels of accuracy and sensitivity are desirable. Here, we used a recently developed computer program that models the transient behavior of a kicking well. Gaskick Program The Gaskick computer program was developed to simulate the evolution of gas kicks in a wellbore. JPT P. 1029

Casing Strain Resulting From Thawing of Prudhoe Bay Permafrost

A compact five-spot well pattern was completed through permafrost at Prudhoe Bay and circulated with hot fluid, creating thaw zones. Compaction Prudhoe Bay and circulated with hot fluid, creating thaw zones. Compaction and deformation of soil in these zones led to casing strain. Analysis determined that casing strains were caused by large differences in compactibility of soil types. Introduction The development of petroleum reserves in the arctic region of Alaska requires new petroleum engineering technology to deal with permafrost problems. A conventional well drilled through permafrost is subjected to the hazards of external freezeback pressures, internal freezeback pressures, and thaw consolidation (compaction). These three major concerns have been studied extensively by operators in the Alaskan arctic. Solutions to the problems associated with the freezeback of shut-in wells have been published in the past four years. Thawing of permafrost around a wellbore also can lead to casing damage. When ice melts, it is reduced approximately 9 percent in volume. Stresses carried through the ice phase of in-situ permafrost tend to transfer to the soil matrix as the ice melts and the pore pressure diminishes because of this reduction. The soil tends to compact when subjected to a higher stress level. The degree of compaction depends on the type of soil, the stress state in the frozen permafrost, the pore pressure after thaw, and the size of the thawed region. Although most compaction is accounted for by lateral movement of the surrounding frozen permafrost, some vertical consolidation or subsidence also can be expected. This vertical consolidation or movement can damage the casing strings throughout the permafrost section. The original field rules for Prudhoe Bay development required that a producing well be protected from subsidence damage by refrigeration, insulation, or other means. To understand thaw consolidation in the thick permafrost at Prudhoe Bay, BP Alaska Inc. conducted a permafrost at Prudhoe Bay, BP Alaska Inc. conducted a field test to thaw a limited region surrounding a well. The amount of thaw in this field test was equivalent to that created around a heavily insulated producing well. Both casing strain and formation movement were detected with a moderate degree of uncertainty in the field data. One solution to the internal freezeback problem is to replace water-base mud with a gelled, weighted oil-base fluid. The thermal-insulating properties of this fluid are quite good. However, a producing well insulated in this manner would develop a larger thaw radius during its operating life than was created in the BP Alaska field test. Petroleum engineers designing casing programs for field Petroleum engineers designing casing programs for field development were uncertain of the effect of this large thaw zone on casing integrity in a producing well. To assess the significance of the consolidation process for a gelled-oil-insulated completion, a major field test at Prudhoe Bay was conducted. The test site was located in Prudhoe Bay was conducted. The test site was located in Section 11, T10N, R15E, in the center of the Prudhoe Bay field and adjacent to a BP Alaska well where numerous cores were taken in the permafrost. Core analysis provided a complete lithology of the permafrost. The provided a complete lithology of the permafrost. The goal of the field test was to observe casing integrity and to measure the strain of a casing string surrounded by a thaw zone equivalent in size to a zone created by a well after 20 year's production. This paper describes the field test, operational aspects, and results. JPT P. 468

Analysis of reservoir pressure and decline curves in Serrazzano zone, Larderello geothermal field

An estimate of reserves in the Serrazzano reservoir was obtained from mass balance studies and production decline curve analyses. The Serrazzano reservoir consists of a geometrically well-defined structural high of permeable formations separated from the other productive regions of the Larderello field. Deep drilling began in the 1930s and was limited to a small area exhibiting natural manifestations. After the second World War the area of drilling was extended to about 20 km 2. Currently the drilling area is about the same. Even though the reservoir has been producing steam since the 1930s, a systematic collection of production data did not begin until after 1953. Data on average reservoir pressures were not available for the material balance calculations made in the study reported here. Calculated bottom hole pressures of shut-in wells were taken therefore to represent local static reservoir pressures. These pressures were used to calculate an “average reservoir pressure” which was graphed as a function of cumulative production. The reservoir pressure history corresponding to the first half of current cumulative production is not known. Data for the second half indicate a linear relationship between “reservoir pressure” and cumulative production. The conventional straight-line p/z vs cumulative production material balance relationship is known to be correct, of course, for closed single-phase gas reservoirs. The validity of this linearity for stream-producing systems with boiling water has not been proved. Regardless of this, the following observations were made: a line connecting the available data points extrapolated back to zero production indicates an initial reservoir pressure approximating at least 40 atm. Extrapolating the same data to zero reservoir pressure indicates the total initial steam in place to be about 170 × 10 6 tons. An empirical type-curve matching technique was applied to the production decline curves of wells in the reservoir. The curve for each well was extrapolated to infinite production time to obtain an estimate of total past and future production. Summing these values for all producing wells in the reservoir, an estimated total production (past and future) of 200 × 10 6 tons was obtained. The agreement between the estimated total production applying material balance principles and decline curve analyses is remarkably good. Although these results may be useful, further field and theoretical work are necessary to prove their validity.

Bacterial Processes for Improved Oil Recovery

Letters to JPT Forum are limited to a maximum of 750 words, including 200 words for each table and illustration. Acceptable subjects include new engineering ideas, progress reports from the laboratory and field, and descriptions of unique equipment, processes or practices. Letters should be sent to the Editor. SPE reserves the right to edit material to eliminate commercialism on remarks of a questionable nature. There is now, and has been for some 30 years, limited research in the area of bacteriological oil recovery. Several patent have been issued as a result of these works. However, concentrated effort is now being given to the problem of oil spills and their cleanup through bacterial methods. The time is right, therefore, to combine and accelerate our research in bacterial oil degradation, and to apply bacterial recovery methods. In this manner we can not only work toward improving the ecosystem but also derive new and economically feasible bacteriological oil recovery mechanisms. The purpose of this article is to briefly discuss bacteriological oil recovery, to stimulate thought, and to promote research in this area. promote research in this area. In the early 1940's, Zobell discovered that bacteria will release oil from sedimentary materials.'," In Dec., 1946, in conjunction with the American Petroleum Institute, he obtained a patent on a process Petroleum Institute, he obtained a patent on a process that involved the injection of anaerobic bacteria into an oil producing formation to increase oil recovery., He named the bacteria that he had isolated Desulfovibrio hydrocarbonociasticus, These bacteria are strict anaerobes and Zobell noted that they grow actively in salt solutions of 25,000 to 125,000 ppm dissolved solids. Also, they are able to tolerate high temperatures. In laboratory experiments Zobell found that the four mechanisms of bacterial oil release are:(1)production of gaseous carbon dioxide,(2)production production of gaseous carbon dioxide,(2)production of organic acids and detergents,(3)dissolution of carbonates in the rock, and(4)physical dislodgment of the oil. Zobell found that bacteria preferentially consume normal paraffins. More recently, with gas chromatography and other tools, this finding has been reaffirmed. Extensive tests of bacteria for oil recovery were made at the Bradford Laboratory of the Pennsylvania Grade Crude Oil Assn. during 1945 and 1946. The results were generally discouraging for bacterial applications in the Bradford area and it was therefore concluded at that time that field tests would not be feasible. However, this finding should now be reviewed and should not be assumed to hold true for present times and different locations. present times and different locations. So far, no results of field tests employing bacterial processes have been published in the U. S. literature. processes have been published in the U. S. literature. However, favorable results have been reported from tests conducted in Poland" and Hungary." The Polish observed oil production increases of 30 to 140 Polish observed oil production increases of 30 to 140 percent with pressure increases from 2 to 25 atm in percent with pressure increases from 2 to 25 atm in several shut-in wells. The pH of the reservoir water dropped from 8.7 to 6.4. There were small decreases in oil viscosity, and in some wells production increases continued for as long as 5 years. Also in Poland, bacteria of the Clostridium type have been isolated; these bacteria reduce heavy hydrocarbons in place to form lighter fractions and gases. Something of this nature could be of great significance to the Athabasca tar sands area. The possibility exists that bacteria can also be used for selective plugging. Since the bacteria and nutrients would be highly concentrated in thief zones, rapid, prolific growth would occur there. prolific growth would occur there. Plugging of the wellbore could be eliminated by separate-stage injection of spores and nutrients followed by a water pad to move the bacteria into the formation. Then a small amount of bactericide could stop the growth at the sand face. In this process the thief zone could be plugged, leaving the wellbore unaffected, and the sweep efficiency could be increased. Another possible application is in the underground production of water-thickening agents. production of water-thickening agents. JPT P. 1469

Planning and Analysis of Pulse-Tests

Developed here are equations that approximate the pulse-test procedure and that, in turn, are plotted as simple graphs that can be used directly to design and analyze these tests. The necessary calculations require only 10 to 15 minutes. Introduction Pulse-testing is a fairly recent procedure that has received some attention in the last 2 years. In this method of testing, a well is pulsed with cycles of injection followed by shut-in, or production followed by shut-in. The pressure response to the cycles is then measured in an offset well. Articles in the literature1,2 discuss, to some extent, the theory of pulse-testing; but an engineer who wishes to analyze the results of such a test will find that he must make a number of tedious exponential integral calculations. The paper briefly covers the theoretical rationale behind pulse-testing, and then develops some approximate equations. As a result of these equations, two simple graphs are developed that can be used for design and analysis of pulse-tests. An example calculation is shown later in the text. General Response Theory Pulse-testing was first discussed by Johnson et al.l The concepts involved are fairly straightforward. Briefly, the bottom-hole pressure in a shut-in well will respond to production or injection cycles in an offset well. The magnitude and timing of the response depend on the flow rate, the permeability, porosity and thickness of the formation, and the compressibility and viscosity of the fluids that lie between the wells. Inhomogeneities, geometry and boundaries also affect the response, but these factors are not included in the scope of this paper, nor in the literature. The equations for the response are line-source solutions to the diffusivity equation. For instance, if a well is produced for a time ?t, then shut in, the equation for the pressure response in the shut-in well isEquation 1 Going further, if there are a number of cycles of production followed by shut-in, if each production rate is equal, and if each cycle lasts for an equal period of time (?t), then by superposition the equation for the pressure response becomesEquation 2 where N is the number of equal-length periods of production and shut-in (for instance, for one production and one shut-in period, N=2; Eq. 1). Eq. 2 is the same as cited by Johnson et al. Notice that each shut-in and production period is assumed equal. This is not necessary, but it is easier to handle theoretically and will be used throughout the rest of this paper. Also notice that Eqs. 1 and 2 are for production and shut-in. For continuity we will continue to speak of production; but the reader should realize that injection and shut-in will work equally well. We would merely reverse the signs.

Case Histories of Production Logging

In injection wells, the main purpose of the production log is to assign volumes or percentages of fluid to each interval taking significant amounts of it. In producing wells the objective generally is to identify zones contributing fluid specifically the quantity of each fluid and its respective entry. Introduction Production logging techniques can be broadly Production logging techniques can be broadly considered to include all types of subsurface measurements subsequent to the initial well completion, and there are undoubtedly instances when these measurements are taken before the actual mechanical completion. There are, practically speaking, two main categories of work into which most production logging falls: injection wells and production wells. The injection wells are generally receiving water as part of a secondary recovery, a pressure maintenance, or sometimes simply a disposal system. The injection medium may also be liquid hydrocarbons, gas (including air), or a combination of liquid and gas such as saturated steam. Whatever the injection fluid, the main purpose of the production log is generally to determine the injectivity profile, that is to quantitatively assign volumes or percentages of fluid to each of the intervals taking significant amounts of fluid. While the profile is being obtained, it is often important to check also for casing failures, packer leaks, faulty cement jobs and interzonal packer leaks, faulty cement jobs and interzonal migration. In producing wells the objective generally is to identify zones contributing fluidwater, oil or gas and more specifically the quantity of each fluid and its respective entry or entries. Static or shut-in wells may also be investigated with production logging techniques. A shut-in temperature production logging techniques. A shut-in temperature profile is a recognized means of qualitatively profile is a recognized means of qualitatively indicating where injected fluids have entered a reservoir. Recent advances in temperature logging present the possibility of identifying oil, gas or water in place in possibility of identifying oil, gas or water in place in the reservoir through the differences in their respective thermal conductivities. Approach to Well Analysis Injection Wells In many instances the relatively high injection rate (1,000 or more barrels per day) and a not too large casing or liner (7 in. OD or smaller) make the continuous spinner a highly suitable tool for attaining the injection profile. Where the continuous spinner is not suited, radioactive tracers can be resorted to; or under certain conditions the "packer-type" flowmeter can be used. A temperature profile is commonly run in conjunction with the spinner or radioactive tracer survey and is particularly useful in defining the presence of a static column if such exists. Producing Wells Producing Wells Since generally at least two phases (oil and water), are present in a producing well, a somewhat different approach must usually be made from that used in a single-phase injection well. If the well conditions and flow rates are suitable, the spinner approach may be used to determine the gross rates involved. (If substantial gas production is involved, the spinner should be useful in defining the entry point or points.) JPT P. 207

Pressure Buildup Behavior in a Two-Well Gas-Oil System

Abstract In analyzing pressure buildup tests for field wells producing both oil and gas, the common practice is to use a modification of single-phase flow theory. Validity of such an approximation has been demonstrated for single-well solution-gas-drive systems. This paper indicates that such approximations are also valid for two-well solution-gas-drive systems, which infers that the technique can be used for multiple-well systems. A computer was used to simulate the behavior of a two-well solution-gas-drive reservoir to test the validity of the above type of analysis. Simulation results indicate that pressure buildup tests in such a system can be analyzed within engineering accuracy for formation permeability and pressure. A rule of thumb is given for estimating the length of time a well must be shut in for the pressure in a nearby producing well to increase significantly. To observe such an increase, the shut-in well would have to be left shut in much longer than normal. INTRODUCTION An important technique for obtaining data concerning a producing petroleum reservoir is the pressure buildup test. Such a test, when properly conducted and analyzed, provides information on the average reservoir pressure and the permeability in the major drainage area of a well. The theory upon which the analysis of a pressure buildup test is based assumes that the behavior of the fluid in the reservoir is adequately described by the diffusivity equation.1 Use of the diffusivity equation implies that a single fluid of small and constant compressibility is flowing. To analyze a pressure buildup test in situations which involve more than one fluid phase, the single-fluid analysis is extended. This paper verifies the extension of pressure buildup analyses to two-phase, two-well systems. Miller, Dyes and Hutchinson1 have presented a technique for analyzing pressure buildup tests in circular bounded reservoirs. Their method requires that the reservoir be producing at pseudo-steady state (constant pressure-gradients) prior to shutin. An alternate reservoir model, presented by Horner,2 assumes that the reservoir is infinite. The Homer model does not assume a pseudosteady state prior to shut-in, but the assumption that the reservoir is infinite implies that the average pressure can be determined only if the total production prior to shut-in is small compared to the total fluid originally present. Limitations imposed by the pseudo-steady state and infinite reservoir assumptions are avoided by the technique proposed by Matthews, Brons and Hazebroek.3 Their method can be used to calculate both the permeability and the average pressure in bounded single-well systems which are not necessarily at steady state. They also suggested determining the average pressure of a multi-well reservoir producing from pseudo-steady state by volumetrically averaging the static pressures of the individual wells. Matthews and Lefkovits4 used numerical simulation techniques to verify that this method does produce adequate results for single-phase, multiple-well systems. Perrine5 proposed modifications to the single-phase theory so that pressure buildup tests in multiple-phase systems could be analyzed. He suggested replacing the single-phase mobility (k/µ) by the sum of the mobilities of the individual phases, and replacing the fluid compressibility by an average compressibility weighted by the saturations of the separate phases. By using numerical techniques to solve the two-phase flow problem for a single-well system, he concluded that this approximation gives results within engineering accuracy. More recently, Weller6 has shown that, for a gas-oil system with a single well at the center of a circular reservoir, pressure buildup tests can be analyzed adequately by using the modification proposed by Perrine. Weller's results also indicate that, as the gas saturation increases, this analysis becomes less accurate.

Reservoir Performance During Two-Phase Flow

Abstract In Part 1, a study of pressure build-up curves calulated for conditions under which both oil and gas flow led to the conclusion that the presence of a dispersed free gas phase in an oil reservoir must be taken into consideration to estimate accurately average reservoir pressure and permeability from build-up curves. Familiar methods based on the assumption of no free gas can be extended to the two-phase case by using total compressibility and mobility in place of single-fluid compressibility and mobility. These methods give correct values for average pressure and permeability when gas saturation is small. Errors become larger as the gas saturation increases. However, for the use to which the results will be put, the methods are satisfactory for reservoir engineering purposes. An improved method of calculating the performance of depletion-type reservoirs is presented in Part 2. Because the mathematical relationships describing simultaneous flow of oil and gas are quite involved, simplifying assumptions are made to provide means of obtaining approximate solutions of reasonable accuracy. One such approximate method now in use is the constant-GOR solution. It involves the assumption that at any instant, the ratio of total gas flow rate (both free and dissolved) to oil flow rate is the same at all points in the reservoir. The approach is not applicable unless the free gas saturation in the reservoir is everywhere greater than the critical gas saturation. This paper presents a modification which, by avoiding the constant-GOR assumption, makes the method applicable to all reservoir conditions, and so far appears to be more accurate than the constant-GOR solution and to be comparable in required computation time. PART 1-BUILD-UP CURVE ANALYSIS Introduction Pressure build-up characteristics of shut-in wells have been used for many years by engineers to evaluate average reservoir pressure, effective permeability thickness of the pay section, effectiveness of well completion (skin effect) and reservoir size. A number of methods of analysis have appeared from time to time. Without exception, these methods are based on the assumption that the reservoir contains but one fluid of constant small compressibility and constant mobility. It has been suggested that these single-fluid methods may be applied to data from reservoirs containing both oil and gas by substitution of some effective total properties of the multiphase system in place of the corresponding single-phase properties. The present investigation was undertaken primarily to evaluate this approach. METHOD A number of theoretical build-up curves were calculated for conditions of two-phase flow, under the assumption of certain reservoir and fluid properties, and were analyzed by single-fluid methods with appropriate total compressibility and total mobility values for the corresponding single-fluid properties. Results of the analyses were compared with the assumed conditions. The theoretical build-up curves were completed by procedures similar to those of West, Garvin and Sheldon. Since these calculations require a considerable amount of computer time, an attempt was made to derive an approximate calculation method. The attempt was unsuccessful for calculating build-up curves, but the effort did result in a new approximate method of calculating the performance of solution gas drive reservoirs, which appears to be an improvement over the constant-GOR method-used previously (see Part 2). The West, Garvin and Sheldon calculations involved the following assumptions: the reservoir is circular and completely bounded, with a completely penetrating well at its center; the porous medium is uniform and isotropic, with a constant water saturation at all points; gravity effects can be neglected; compressibility of rock and water can be neglected; the composition and equilibrium are constant for oil and gas; the same pressure exists in both the oil phase and the gas phase; and no after production occurs, i.e., the well is shut in at the sand face for build-up. These assumptions make it possible to describe two-phase flow of oil and gas by the partial differential equations: ,......(1) and .......(2) To obtain idealized build-up curves for analysis, these equations were solved numerically with certain hypothetical PVT data, relative permeability data and reservoir parameters. With the use of total compressibility and total mobility, average reservoir pressures were calculated from the curves by the method described by Matthews, Brons and Hazebroek; effective permeability thickness values were calculated from the slopes of the curves by the usual single-fluid method: ..................(3) JPT P. 240ˆ