Nonproducing Wells Research Articles

Methane Emissions from Non-producing Oil and Gas Wells and the Potential Role of Seismic Activity: A Case Study in Northeast British Columbia, Canada.

Increasing seismic activity due to fluid injections for oil and gas production may be contributing to leakage along non-producing oil and gas wells and emitting methane, a potent greenhouse gas. However, the extent to which nearby seismicity may drive or exacerbate methane emissions and cause well integrity issues is unknown. Therefore, we analyze field evaluations at 448 non-producing oil and gas wells in Northeast British Columbia (NEBC) and geospatially analyze oil and gas well and fluid injection data alongside locations of 3515 earthquakes from 2001 to 2021 and 130 faults. Through analysis of ground and helicopter-based field evaluations of non-producing wells in NEBC, we show that methane emission rates of non-producing wells average at 8301 mg/h/well but vary by 10 orders of magnitude. We find that higher methane emission rates (milligrams of methane/h/well) are observed at wells with larger flowing pressures at the wellhead during completion (kPa) and with shorter distances (m) to earthquakes, particularly at plugged wells. These results imply that seismicity may increase the likelihood of non-producing well integrity issues and methane leakage, thereby also exacerbating groundwater contamination and environmental degradation risks.

Documented Orphaned Oil and Gas Wells Across the United States.

Orphaned oil and gas wells are unplugged nonproducing wells with no solvent owner of record to plug and mitigate them, such that the responsibility often falls on government agencies and the general public. Unplugged wells pose risks to the environment, climate, and human health. To develop a national framework to quantify the environmental benefits of plugging and optimize mitigation, we analyze oil and gas well data from state agencies across the United States to estimate the number of documented orphaned wells over time and evaluate their attributes. We find at least 81,857 documented orphaned wells as of September 2021 and 123,318 as of April 2022, representing 2% and 3%, respectively, of all estimated abandoned wells in the United States. We identify at least 20,286 potentially documented orphaned wells as of September 2021 (0.5% of all estimated abandoned wells in the country), of which 8% became documented orphaned wells as of April 2022. We estimate annual methane emissions to average 0.016 ± 0.001 MMt of CH4 for the 123,318 documented orphaned wells as of April 2022, corresponding to 5–6% of the total methane emissions estimated by the U.S. EPA for all abandoned wells. Although well type (i.e., oil vs gas) is generally available (83% of the 81,857 documented orphaned wells as of September 2021), only 49% and 16% of the wells have information on depth and last production date, respectively. Overall, documented orphaned wells and their attributes, including location, well type, depth, and last production date, require additional characterization and studies to constrain the uncertainties. Nevertheless, our identification and analysis of documented orphaned wells represent the first steps toward characterizing the full set of wells eligible to be plugged and remediated with the federal funding available in the U.S. via the Infrastructure Investment and Jobs Act. Our results can also be useful for the management of the hundreds of thousands, potentially a million, undocumented orphaned wells likely to exist across the nation.

Integrating the Geology, Seismic Attributes, and Production of Reservoirs to Adjust Interwell Areas

Abstract —Dynamic models of the seismic, geological, and flow characteristics of a reservoir are the main tool used to evaluate the potential of drilling new infill wells. Static geological models are mainly based on borehole data combined with dynamic analyses of production dynamics. They are used to determine the redevelopment of and adjustments to new drilling locations; however, such models rarely incorporate seismic data. Consequently, it is difficult to control the changes in geological models between wells, which results in the configuration of well positions and predicted results being less than ideal. To improve the development of adjusted areas in terms of their remaining oil contents, we developed a new integrated analysis that combines static sediment modelling, including microfacies analysis (among other reservoir and seismic properties), with production behaviours. Here, we illustrate this new process by (1) establishing favourable areas for static geological analysis; (2) studying well recompletion potential and the condition of non-producing wells; (3) conducting interwell analyses with seismic and sedimentary data; (4) identifying potential sites constrained by seismic and geological studies, as well as initial oilfield production; (5) providing suggestions in a new well development plan.

Texas Says No to Oil Production Quotas, Yes to Well-Plugging and Pit-Cleanup Delays

After weeks of talk and deliberation, the Texas Railroad Commission officially decided it will not go back into the production management business. Rather than trying to influence prices, the commissioners changed a handful of rules to allow operators to delay the plugging of wells and the cleaning up of waste pits, reduced fees and fines, and encouraged construction of new underground oil storage facilities. Those motions preceded the final decision on a plan to try to push up oil prices by cutting production. The lone commission member who had supported a 20% production cut, Ryan Sitton, did not bring up the motion because it was clear he did not have the votes to pass it on the three-member commission. Railroad Commission Chairman Wayne Christian said there was no point in cutting Texas production unless other states and producing countries would do the same. “We could not confirm any other state would join us and that was a requisite of the motion,” based on a request for action submitted by Pioneer Natural Resources and Parsley Energy, Christian said. He also pointed to the opposition of every oil and gas industry association to state intervention at a time when producers are cutting production because of low prices and dwindling oil storage space. When the chairman proposed to dismiss the motion, which led to a marathon hearing in April, Sitton said he would oppose it because “Parsley and Pioneer asked us to determine reasonable market demand, which we did not do.” The commission has begun gathering data to answer a critical market variable - how much storage is available in Texas. As of 20 April, unfilled storage capacity owned by Texas refineries and pipeline companies was 71.2 million bbl (about 75% responded to the commission’s query). To encourage more storage, the commission passed an emergency motion allowing underground oil storage in formations other than salt domes. Producers will need to convince commission staffers that the formation will securely contain the oil and not harm water supplies. To speed the process, no hearing will be required except for protests of the commission’s ruling. Also, several fees were waived as an incentive to build storage. Some of the fees, related to injection into disposal wells, could benefit a broader group of companies. Also, in the name of helping struggling operators, the commissioners extended the deadlines for plugging nonproducing wells and cleaning up waste pits from 1 year to 2 years. Commissioner Christi Craddick said the plugging change would apply to marginal wells with some production this year that produce nothing for the year beginning after 1 March. The hope is it will help some companies stay in business, and perhaps allow the restarting of some of those wells in the future. But Sitton pointed out that industry conditions now are so bad that the commission might inherit a lot of wells and pits that need cleanup after oil companies have failed. Paul Dubois, assistant director at the commission, said that in past downturns the commission had taken on more abandoned wells and facilities. The cleanups are supposed to be paid by the financial security insurance required of operators. The hope is that the extended deadlines will reduce current expenses for financially pressed operators. “Maybe there will be some more liabilities, but also some more operators around to take care of it” because they did not have to pay to comply this year,” Craddick said. The potential cost of abandoned wells and pits is unknown. Dubois said the commission has “not enumerated” the number of wellsites that will be left behind after this deep downturn. The potential cleanup cost is likely to be significantly higher than after the 2014 price crash. After years of high-volume drilling, the percentage of older, low-producing wells is much greater, as is the pressure on producers.

Waterflooding Development Prediction in Carbonate Reservoir at Field X using Reservoir Simulation

Field X consist of a carbonate reservoir, producing since April 2014 with only 2 existing wells present, which is well NF-01 and NF-02. Production history of the field was performed from year 2014 until 2016. The original oil in place of Field X is 9.204 MMSTB (volumetric) and 9.0308 MMSTB (simulation). A method of optimizing Field X is Waterflooding after primary recovery has been done. In this study, the software used for the development of Field ‘X’ is Computer Modeling Group (CMG) IMEX Black Oil, by applying waterflooding as a method of optimizing the field, the optimization can be determined based on the consideration of various development scenarios. Reservoir simulation process consists of several steps which are; data preparation, model and grid construction, initialisation, history matching and prediction forecast. All the data up until history matching was given and the focus of this paper is to evaluate and predict several scenarios. The period of development is done for 19 years which is until December 2035. Several scenarios predicted were In-fill, conversion of wells, peripheral, 5-spot patterns and pilot studies. As the prediction developments were conducted, recovery from each scenario varies. These scenarios are then compared to be able to find the optimum result. After simulating several scenarios of as follows; infill-18 wells, infill-26 wells, infill-horizontal wells, covert all non-producing wells, peripheral wells, invert and normal 5-spot wells and comparing the recovery factor, it can be said that waterflooding implementation was insignificant as there were only a slight increase in recovery factor. The optimum scenario from waterflooding implementation is the peripheral pattern with a recovery factor of 38.17%.

Dynamic model of Tertiary reservoir in Khabaz Oil field

This study deals with building a reservoir model for Tertiary reservoir in Khabaz oil field and calculate oil and gas in place by volumetric method using Petrel RE software and by Dynamic method through material balance by using MBAL software, testing the reservoir dynamic model through history match over 26 years, and predicted (4) case of reservoir and well performance over 29 years start at the end of history match (1/1/2016 ) until (1/1/2045) by natural depletion for case-1 Do nothing (current producing wells), Case-2 Base case (work over non-producing wells) case-4 new wells ( drill 6 new wells) and add water injection for case-3 (drill 7new water injector wells).

Application of Ensemble Variance Analysis in the Development of the Wheatstone Field Startup Strategy

Summary Starting initial field production is a unique opportunity to acquire reservoir–surveillance information that can impact future reservoir performance. When a field is perturbed by first production, there is the potential to reduce uncertainty in reservoir properties by monitoring the pressure changes at nonproducing wells with downhole pressure gauges and comparing the observed signal with a range of simulation–model results. The Wheatstone Field, located offshore of Northwest Australia, recently began production startup to supply gas to the Wheatstone liquefied–natural–gas (LNG) facility. The operational guidelines required each development well to start with a single–well–cleanup flow to the Wheatstone platform. The initial single–well–cleanup flows of the Wheatstone field provided scope for selecting a well flow sequence with observation at nonproducing wells. The recommended sequence of initial cleanup flows was designed with a focus on reducing reservoir uncertainties by means of ensemble variance analysis (EVA). EVA is a statistical correlation technique that compares the covariance between two sets of output data with the same set of inputs. For the Wheatstone Field well–cleanup flow sequence selection, the EVA workflow compared the full–field design of experiments (DoE) study of field depletion and a series of short early–production reservoir–simulation DoE studies of the gas field. The covariance between the two DoE studies was evaluated. The objective of the EVA approach was to determine the startup sequence that would allow for the best opportunity to reduce subsurface uncertainty. This objective was met by ranking multiple cleanup flow sequence scenarios. The key factors considered for sequence selection ranking were the impact on business objectives, such as future–drilling–campaign timing and location of infill wells, and insights on reservoir connectivity, gas initially in place (GIIP), and permeability. The recommended sequence of well–cleanup flows uses a superpositioned pressure signal to boost response at observation wells, which improves measurement resolvability. The selected sequence preserves key observation wells for each manifold and reservoir section for as long as possible before those wells are required to be flowed to meet operational requirements. Operational constraints and variations of the startup plan were considered part of the evaluation.

Concurrent Decommissioning Method Enables Safer, Lower-Cost Process

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26867, “Decommissioning-Process Optimization Methodology,” by G.L. Siems, SPE, Petroleum Asset Retirement Specialists, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission. With regulatory pressure and the cost of decommissioning increasing, many operators are seeking new and better decommissioning methods that could get more work done safely and at a lower cost. New technologies have made possible a new, optimized decommissioning methodology. The size and capabilities of a newly designed and constructed liftboat allowed a departure from the traditional method of performing decommissioning work steps sequentially to a new method of performing the majority of work steps concurrently. Introduction A government study and subsequent safety alert following the severe hurricanes of 2004 and 2005 that toppled 123 structures and 800 wells in the US Gulf of Mexico outer continental shelf prompted the US Minerals Management Service to recommend that “operators … review and evaluate their inventory of nonproducing wells and facilities to determine the future utility of these structures and the level of threat posed to the environment and human safety should a facility experience a catastrophic loss.” Following another severe hurricane season in 2008, when another 200 wells and 54 structures were damaged or toppled, the US Department of the Interior’s Bureau of Ocean Energy Management Regulation and Enforcement issued Notice to Lessees (NTL) No. 2010-G05, commonly referred to as the “Idle-Iron NTL.” This NTL, for the first time, provided decommissioning guidance for wells and structures on active leases reaching far beyond the decommissioning requirements codified into law that only required decommissioning within 1 year of lease expiration or lease relinquishment. The newly issued guidelines specified the maximum number of years that wells and structures were allowed to remain idle before they had to be decommissioned and removed. Lease operators now had to decommission and remove wells and structures no longer useful for oil and gas production as soon as possible but no later than 5 years after cessation of production. Offshore oil-and-gas-facility decom-missioning activities are inherently hazardous because they often involve workers performing various tasks in, on, and around oil and gas wells, platforms, and production facilities that have no future utility for hydrocarbon production. Some of these facilities may have been idle for many years and could be in various stages of decomposition, depending on their age and the level of maintenance per-formed over their life time. A new, optimized decommissioning methodology was made possible through the use of a newly designed and constructed 335-ft-class self-elevating, self-propelled liftboat. The size and working capabilities of this new vessel allowed a departure from the traditional method of performing decommissioning work steps sequentially to a new method of performing the majority of work steps concurrently.

Seismic-petrophysical reservoir characterization in the northern part of the Chicontepec Basin, Mexico

The Chicontepec Formation in east-central Mexico is comprised of complex unconventional reservoirs consisting of low-permeability disconnected turbidite reservoir facies. Hydraulic fracturing increases permeability and joins these otherwise tight reservoirs. We use a recently acquired 3D seismic survey and well control to divide the Chicontepec reservoir interval in the northern part of the basin into five stratigraphic units, equivalent to global third-order seismic sequences. By combining well-log and core information with principles of seismic geomorphology, we are able to map deepwater facies within these stratigraphic units that resulted from the complex interaction of flows from different directions. Correlating these stratigraphic units to producing and nonproducing wells provides the link between rock properties and Chicontepec reservoirs that could be delineated from surface seismic data. The final product is a prestack inversion-driven map of stacked pay that correlates to currently producing wells and indicates potential untapped targets.

Association between magnetic susceptibilities and hydrocarbon deposits in the Barinas-Apure Basin, Venezuela

We have measured the magnetic susceptibility of 5425 drill cuttings, coming from 20 oil wells distributed in eight fields of the Petroliferous Barinas-Apure Basin (Barinas, Venezuela), seeking evidence of magnetic anomalies associated with the presence of hydrocarbon deposits. The rock samples are located between the near earth’s surface and the basement’s top (approximately 4000 m). In the magnetic susceptibility profiles, we observed high magnetic susceptibilities at the top of the sedimentary units corresponding to reservoir and source rocks of oil-producing wells, whereas in the case of nonproducing wells we observed low magnetic susceptibilities. A basic statistical analysis of the magnetic susceptibility measurements shows a significant difference between the mean values across producing and nonproducing wells at the correspondent oil-related formations, with a ratio of [Formula: see text] of producing to nonproducing wells. In the producing wells, we have found a relation between the magnitudes of the magnetic susceptibility and the age of the formation; the larger the magnetic susceptibility, the younger the geological stratum. The age and depth of the formations where the cuts were obtained exclude the presence of cultural (human origin) contamination of the samples, suggesting the evidence of authigenic origin of the magnetic minerals due to the reductive effect of hydrocarbons in rocks.

Magnetic and mineralogical studies to characterize oil reservoirs in Venezuela

High-resolution aeromagnetic surveys over oil fields and magnetic susceptibility (MS) measurements in soils, sediments, and drill cuttings have been proposed as complementary or alternative means of exploration and assessment of hydrocarbon reservoirs. Some micromagnetic anomalies detected by these studies could be the likely result of the existence, at shallow depths, of authigenic magnetite and/or Fe-sulphides. It has been hypothesized that such magnetic minerals are the chemical byproducts of primary Fe-oxides exposed to a reducing environment induced by the underlying reservoir. Secondary magnetite could appear as spherical aggregates (framboids) of submicronic crystals identifiable by scanning electron microscopy (SEM). The formation of these framboids seems linked either to inorganic chemical processes associated with the presence of hydrocarbons or to oil biodegradation. In the last few years, we have examined the causal relationship between framboids of magnetic minerals and hydrocarbons via rock magnetic and electron paramagnetic resonance (EPR) analyses of drill cuttings. The samples used have been taken at different depths (within the first 1500 m) of producing and nonproducing wells from two oil fields in southwestern Venezuela. We have complemented MS results with S-ratio logs, SEM, X-ray energy dispersion (EDX), IRM acquisition curves, and high-temperature susceptibility measurements. More recently we have also studied soil samples from an oil prospective area in western Venezuela, where rock magnetic and EPR results were compared with ethane gas analyses and remote sensing data. Rock magnetic and EPR studies have been performed in 14 oil wells from La Victoria (3) and Guafita (11) fields (Figure 1). Since our research has focused at the near-surface expression of hydrocarbon migration, the samples analyzed (drill cuttings) were taken from different depth at intervals of about 15 m between 100 and 1500 m. All samples belong to a single group of molasses from strata that lie far above the producing levels …

Evaluation of the reconnaissance results in geothermal exploration using GIS

Geographical Information System (GIS) is used to determine the spatial association between geophysical and geological evidence and production zones in a well-known geothermal field (Los Azufres, Mexico). Surface observations in Los Azufres were used to delineate areas characterized by high permeability and hot fluid transport from the reservoir: main faults, superficial fracture density, surface manifestations, contacts with the most recent rhyolite domes, and low values in the apparent resistivity surveys. Three knowledge-driven models were constructed based on a conceptual model of the field: a hydrothermal system in rough terrain with secondary permeability. Boolean, Index Overlay and Fuzzy scheme models were proposed and the results obtained show a good correlation with the location of the producing and non-producing wells that have been drilled in the field. The results obtained are useful for well siting (Boolean and Low-Risk Fuzzy models) or for planning further detailed exploration (Index Overlay and High-Risk Fuzzy models).

Recent California Policy Developments for Oil and Gas Leases Concerning Nonproducing Wells and Proposed Well Operations

Recent California Policy Developments for Oil and Gas Leases Concerning Nonproducing Wells and Proposed Well Operations

Hydrocarbon Production Potential of Mississippian Rocks in Cowley County, Kansas: ABSTRACT

Petroleum geologists are continually searching for new and better techniques of exploring for hydrocarbons. This study uses one such technique, discriminant function analysis, to predict trends of potential hydrocarbon production of Mississippian rocks in Cowley County, Kansas, Discriminant function analysis is a method of studying differences between two or more groups, using a set of discriminating variables. The two groups used for this study were (1) wells producing from the Mississippian and (2) wells not producing from the Mississippian. Variables used were thought to be potentially significant to hydrocarbon accumulation in Mississippian rocks within the study area. These variables included structural tops and thicknesses, surface elevation, presence of tripolitic Mississippian chert, trend surface residuals, and four types of satellite lineation data. A total of 564 wells, each with 21 distinct parameters, was used in performing the two-phased analysis. The two phases, consisting of a principal components analysis and the discriminant function analysis, were accomplished through use of computer programs and resulted in a single discriminant score value for each well. These values were used to generate a discriminant score surface map. Statistical analysis of the map resulted in 80.6% of the producing wells being correctly classified within producing areas. Alternately, 75.9% of the nonproducing wells were correctly classified. These favorable results suggest that this technique could be successful in establishing trends of production and potential production while simultaneously delineating areas of nonproduction. End_of_Article - Last_Page 314------------

Fluid-mineral equilibria in a hydrothermal system, Roosevelt hot springs, Utah

The availability of fluids and drill cuttings from the active hydrothermal system at Roosevelt Hot Springs allows a quantitative comparison between the observed and predicted alteration mineralogy, calculated from fluid-mineral equilibria relationships. Comparison of all wells and springs in the thermal area indicates a common reservoir source, and geothermometer calculations predict its temperature to be higher ( 288°C ± 10°) than the maximum measured temperature of 268°C. The composition of the deep reservoir fluid was estimated from surface well samples, allowing for steam loss, gas release, mineral precipitation and ground-water mixing in the well bore. This deep fluid is sodium chloride in character, with approximately 9700 ppm dissolved solids, a pH of 6.0, and gas partial pressures of O 2 ranging from 10 −32 to 10 −35 atm, CO 2 of 11 atm, H 2S of 0.020 atm and CH 4 of 0.001 atm. Comparison of the alteration mineralogy from producing and nonproducing wells allowed delineation of an alteration pattern characteristic of the reservoir rock. Theoretical alteration mineral assemblages in equilibrium with the deep reservoir fluid, between 150° and 300°C, in the system Na 2O-K 2O-CaO-MgO-FeO-Fe 2O 3-Al 2O 3-H 4SiO 4-H 2O-H 2S-CO 2-HCl, were calculated. Minerals theoretically in equilibrium with the calculated reservoir fluid at >240°C include sericite, K-feldspar, quartz, chalcedony, hematite, magnetite and pyrite. This assemblage corresponds with observed higher-temperature ( >210°C) alteration assemblage in the deeper parts of the producing wells. The presence of montmorillonite and mixed-layer clays with the above assemblage observed at temperatures <210°C corresponds with minerals predicted to be in equilibrium with the fluid below 240°C. Alteration minerals present in the reservoir rock that do not exhibit equilibrium with respect to the reservoir fluid include epidote, anhydrite, calcite and chlorite. These may be products of an earlier hydrothermal event, or processes such as boiling and mixing, or a result of errors in the equilibrium calculations as a result of inadequate thermochemical data.

Oswego Limestone, Aline-Lambert Fields, Oklahoma--Source, Reservoir, and Trap: ABSTRACT

The unitized Aline-Lambert field covers about 150 sq mi (241 sq km) in Alfalfa County, Oklahoma. Aline field produces oil from two or more porous zones in the Oswego Limestone whereas the Lambert field produces primarily gas but locally contains a thin oil column. Porous and permeable zones are discontinuous in this gas-solution drive reservoir. Gas-water and oil-water contacts in the field drop to the southeast at about 20 to 45° in the direction of regional dip. The trap is a porosity pinch-out. The Oswego Limestone is composed of intercalated mudstones, wackestones, and packstones that range in thickness from 30 to 40 m. Maximum production in the field is from wells that penetrate a complex system of phylloid algal mounds. Distribution of the mounds is controlled by a break in slope from shallow shelf waters into a deeper water, northeast-trending embayment. Porosity values within the field range from 6 to 12%; permeabilities vary from 2 to 300 md. Porosity and permeability in non-producing wells in the area average 5% and 4 md. Five stages of cementation and partial dissolution have been recognized. Texture and isotopically light carbon values of the later stage cements suggest that they were in part formed during biochemical degradation of organics. Initial correlation of hydrocarbons produced from the reservoir suggests that the Oswego was the source. Samples of the Oswego, juxtapositional strata, and oil and gas were processed and analyzed chromatographically for correlation studies. Organic extraction schemes involved the standard separation of alkane and aromatic fractions by column chromatography. Hydrocarbon fractions were analyzed by gas chromatography using glass capillary columns and flame ionization detection. In addition, total organic-carbon percentage in rock samples was determined by combustion and the resulting carbon dioxide was analyzed for its carbon isotopic composition. The resulting ^dgr13C values suggest a relation between indigenous organic matter and the later stage cements. End_of_Article - Last_Page 784------------

Perforating Resin-Consolidated Zones for Capacity Improvement

Sand control using epoxy resin consolidation usually is effective, but treated wells fail to produce occasionally. This, paper presents field results showing that through-tubing jet reperforation of wells into the previously resin-consolidated zone can restore production. previously resin-consolidated zone can restore production. Laboratory tests indicated clean, productive perforations and undamaged resin consolidation. Introduction Reservoirs from surface to 8,000 ft and deeper off the Louisiana coast are notorious sand producers. Excessive sand production can result in separation and disposal problems, erode pipe and equipment, damage casing, problems, erode pipe and equipment, damage casing, and shutdown pumps. Sand control is necessary in wells of this type. From 1958 to 1972, when multiple completions were most common, Chevron Oil Co. elected to complete many wells dually with two-stage gravel packs in lower zones and resin consolidation in upper zones. Any selective (single) zones also were resin consolidated. Both sand control methods have proven highly successful. However, in several instances some resin-consolidated zones failed to produce, and acidizing also failed to induce flow. Assuming sand or mud fillup is not blocking the perforations, it has been proposed that unintended dirt or debris injected with the resin and associated fluids may plug perforations or damage near-well formation plug perforations or damage near-well formation permeability. permeability.After all other methods failed to induce flow from these wells, reperforation with through-tubing, jet-perforating guns gave promising results. Field Work Six nonproducing or low-production resin-consolidated wells were reperforated. Two other selected wells were not reperforated because of mechanical problems encountered. The selected wells are located east of the Mississippi River delta in the Main Pass area. The productive section is Upper Miocene in age, with sands and productive section is Upper Miocene in age, with sands and shales deposited in a near-shore marine environment. As the electric logs (Fig. 1) suggest, some sands are massive and relatively clean with porosities of 30 to 35 percent, while others are argillaceous with lower porosity. The eight wells represented two different types of completion. One was the selective zone completion (Fig. 2). Casing was perforated, sand was resin consolidated and packers were placed on single tubing string, isolating the zones at initial completion. Only one zone was produced at a time, starting at the bottom and progressing up produced at a time, starting at the bottom and progressing up the tubing. When moving to an upper selective zone, lower zones were plugged off and a special tubing perforator was used to open the tubing between the packers perforator was used to open the tubing between the packers isolating the selective zone to permit flow. In contrast, when using the reperforation completion technique, the reperforating gun in a selective zone must perforate both tubing and casing. A through-tubing, expendable, capsule-type, jet perforating gun was used. Shot density was four shots per foot, oriented at a 90 degrees angle. Wells 1 and 2 were selective zone completions. The second type was the standard dual completion (Fig. 3). Two strings of tubing allowed simultaneous but separate production from both zones. In our examples, only the upper zone was resin consolidated. To reperforate these zones, the perforating gun was lowered through the short tubing string until it hung free in the upper zone. Only the casing was penetrated. JPT P. 283

A Stochastic Inventory Model for Scheduling Development Drilling

Abstract Employing the methodology of operations research, a mathematical model is formulated to schedule the development drilling of an oil field. The objective of the model is to minimize the total discounted cost of the development operation, and the decision variable is the number of wells drilled as a function of time. The model is analogous to an inventory problem in which the penalty assessed for failing problem in which the penalty assessed for failing to meet the demand for crude oil is balanced against the cost of drilling, completing, and equipping wells and the cost of transporting rigs and personnel to and from the development area. Because of the requirement that a single decision maker controls the scheduling, the model is particularly applicable to the development of fields in foreign countries. Since the production rates from future wells are unknown and some uncertainty exists in the projected crude oil demand, neither the field producing capacity nor the demand can be treated deterministically, but must be considered as random variables. Assuming that the production rates are independent, log-normally distributed random variables and the demand is normally distributed; the expected shortage is derived as a function of the number of wells drilled and completed. An option is also provided to include a uniformly distributed demand. provided to include a uniformly distributed demand. Once the field is placed on production, the mean and variance of the production rates will decline in proportion to the remaining reservoir energy. The proportion to the remaining reservoir energy. The model is structured so that the mean and variance of the production rates can be adjusted for any type of producing mechanism; therefore, the drilling schedule is planned not only to satisfy a projected demand rate but also to offset the loss in producing capacity when the field is placed on production. The total cost function results in a nonlinear unconstrained minimization problem, which is solved by the pattern search technique of Hooke and Jeeves. The solution to the model demonstrates the sensitivity of the drilling policy to the unit shortage cost and shows that there exists a unit shortage cost below which the field cannot be developed economically. Introduction The exploration and production of crude oil and natural gas are classic examples of decision making under uncertainty. irrespective of the technological advances in the fields of geology, geophysics, geochemistry, and reservoir engineering, the presence of commercial hydrocarbon deposits can presence of commercial hydrocarbon deposits can only be proved by a substantial investment in the drilling of one of more wells. Geologists have long recognized the stochastic nature of hydrocarbon deposits and several interesting prospecting models have been derived. Dowds prospecting models have been derived. Dowds proposed that the rock-hydrocarbon distribution proposed that the rock-hydrocarbon distribution within a geographical area could be studied as a Markov chain. using this approach, he found that the Markov chains from well-to well and area-to area tended toward statistical equilibrium. By contouring the statistical entropy, he was able to isolate areas with the highest probability of finding oil. An interesting application of discriminant analysis was presented by Wignall, in which well and field data were analyzed in order to define a discriminant function that could be used to differentiate between producing and nonproducing wells. producing and nonproducing wells. Grayson, in a famous application of utility theory, proposed that alternative drilling locations be examined on the basis of their expected utility. Kaufmann later improved on this work by showing that, within a given sedimentary basin, reserves were log-normally distributed. Once oil has been discovered and responsibility for developing these reserves has been transferred to the production department, petroleum engineers historically have ignored risk and uncertainty and have considered the development drilling problem as a deterministic one. The first approach toward scheduling the development drilling of a field was given by Aronofsky and Williams. They formulated the problem as a linear programming model with the objective of maximizing the present worth of future net income.