Stock Tank Barrels Research Articles

Optimizing Water-Cut and Boosting Oil Recovery: Geological Insights from Mishrif Reservoir, Buzurgan Oil Field

This study utilizes streamline simulation to model fluid flow in the complex subsurface environment of the Mishrif reservoir in Iraq's Buzurgan oil field. The reservoir faces challenges from high-pressure depletion and a substantial increase in water cut during production, prompting the need for innovative reservoir management. The primary focus is on optimizing water injection procedures to reduce water cuts and enhance overall reservoir performance. Three waterflooding tactics were examined: normal conditions without injectors or producers, normal conditions with 30 injectors and 80 producers and streamline simulation using the frontsim simulator. Three main strategies were employed to streamline water injection in targeted areas. Over a 22-year forecasting period and employing seven Strategies, streamline simulation were optimized both oil and water outputs. The hybrid Strategy-7 as mixed between all three outperformed Strategy-1 that was gave highest optimization result for only one strategy, yielding the highest cumulative oil production of 1281 million stock tank barrels, the highest oil recovery factor of 24.1%, and a minimal of 2.5% water cut. This study underscores the importance of streamline simulation in managing reservoirs under challenging subsurface conditions, highlighting that a thoughtful integration of streamlining tactics can significantly improve reservoir performance even enhancing oil recovery and addressing water-related issues. The findings contribute valuable insights for optimizing waterflooding strategies in similar globally geological contexts.

3D static modeling and sequence stratigraphy using well logs and seismic data: An example of Abu Roash G member in Bahga oilfield

This research uses both three-dimensional (3D) modeling and geologic well control to piece back together the architectural parts of the Late Cretaceous formations. The goal is to figure out the sizes, directions, locations, and controls of the layers of the fluvial sandstone reservoirs. Sequence stratigraphy is essential for 3D reservoir modeling and petroleum geology understanding in the Bahga oilfield. The purpose of this work is to create a static model that shows the layers and facies distribution in the reservoir interval. We will use data from nine well logs and 22 seismic lines calibrated by the Abu Roash G Member reservoir core intervals to accomplish this. The petrophysical study discovered three parts in the Abu Roash G Member reservoir rock: channel fill that is affected by tides, channel fill that is dominated by tides (intertidal sands), and channel top with lenticular bedded sandstone. The model's findings point to the existence of an NNW-oriented sand body, which could be a prime location to produce hydrocarbons. The original oil in place (OOIP) is about 3,438,279 Stock Tank Barrels (STB), and the oil reserve reaches up to 1,031,484 (STB). Sequence stratigraphic analysis using seismic and well log information (SB) reveals that the Upper Cretaceous AR/G reservoir of the Bahga field is characterized by third- and fourth-order stratigraphic sequences, which are constrained by three Maximum Flooding Surfaces (MFS) and two Sequence Boundaries. The integration of the derived geological model and sequence stratigraphic results can lower future extraction risk by identifying the locations and trends of the geologic facies with the necessary petrophysical properties for the hydrocarbon accumulations.

3D petroleum reservoir modelling using seismic and well‐log data to assess hydrocarbon potential in Abu Roash (G) Member, Karama Oil Field, North‐Western Desert, Egypt

Since 2002, the Upper Cretaceous Abu Roash (G) Member in the Karama Oil Field has been considered to be one of the most important reservoirs in the Abu Gharadig Basin in the North‐Western Desert. This member is located in the Karama Oil Field. For the purpose of increasing oil production, a three‐dimensional reservoir model was developed, and the area's oil resource was determined by employing thirty two‐dimensional seismic lines dispersed in the north–south and east–west directions, in addition to five well logs. Within the Abu Roash Formation, which conformably overlies the Bahariya Formation and unconformably underlies the Khoman Formation, there are seven normal faults that allow for three‐way dip closure for oil accumulation. These faults cut through the Abu Roash Formation. The Abu Roash (G) Member is mostly composed of limestone, shale and intercalated siltstone and sandstone, and it ranges in thickness from 54 to 168 feet (16.5 to 51.2 m) in terms of its net pay. Effective porosity ranges anywhere from 20% to 30%, shale content can be anywhere from 13% to 24%, water saturation can be anywhere from 40% to 55% and hydrocarbon saturation can be as high as 60%. Through the integration of the constructed structural and property models, two new prospect areas have been presented (in the northern part of the study area). In these areas, the petrophysical parameters are good, and the Original oil in place (OOIP) is predicted to be 1107 × 106 Stock Tank Barrels (STB), which will help with the development plans for the study area.

Activation of a non-eruptive well by using an electrical pump to optimise production

The purpose of the study is to activate a well named X (for confidential reasons) in order to improve its production by proposing an electrical submersible pump. The nodal analysis is performed to understand the well’s condition and an economic evaluation is done to determine the applicability of the project. The initial completion data, the pump placement data and the economic data are considered and used as input in PIPESIM 2017 software for operations and simulations. The results obtained from nodal analysis show that the well is in a total depletion situation. Upon analysis, the electrical submersible pump type REDA S6000N with operational diameter of 5.38 inches is appropriately chosen and installed, resulting in a flowrate of 4,891.36 stock-tank barrels per day (stb/d) with a bottom pressure of 2,735 pounds per square inch (psi). A flowrate of 5,000 stock-tank barrels per day at a pressure of 2,707 psi is obtained after optimisation of the pump through sensitivity curves. The economic balance sheet presents a net present value of USD 110,718,250, showing the profitability of the project over a period of one year.

Ultimate expellable potentials of source rocks from selected super basins: What does “world class” look like?

An important step in the evaluation of a play or prospect is to consider the potential supply of petroleum charge, which is ultimately constrained by masses and volumes supplied by the source bed. The two factors limiting the mass of petroleum expelled from the organic matter in the source bed are (1) its initial expulsion potential and (2) the cumulative fraction of potential that has been expelled up to its maximum state of maturation. To evaluate the initial expulsion potential, we introduce a workflow to estimate the ultimate expellable potential (UEP), divided into an oil potential (UEO) and a gas potential (UEG), which represent the cumulative masses of oil and gas that can be expelled upon complete maturation of the source rock. For use in resource estimation, these masses can be converted to surface volumes of oil and gas per unit area (million stock tank barrels per square kilometer and billion standard cubic feet per square kilometer or million barrels of oil equivalent per square kilometer, respectively). The UEP (UEO, UEG) can be mapped across the depositional extent of the source bed, just as a reservoir depositional system is mapped. These potentials per unit area constitute the first level of quantitative resource estimation in the evaluation of a play or prospect. We show examples of UEP (UEO, UEG) mapping based on available public data. Three of the example source rocks are aquatic organofacies that have charged major conventional petroleum systems: the Callovian to Oxfordian marine organofacies of the Arabian Basin, Saudi Arabia; the Volgian marine organofacies Bazhenov Formation of the West Siberian Basin, Russia; and the Eocene–Oligocene lacustrine freshwater organofacies Shahejie Formation of the Bohai Basin, China. We also include an unconventional system: the uppermost Devonian–lowermost Mississippian marine organofacies Bakken Formation of North Dakota, United States. The UEPs of the studied source rocks in the Arabian Basin and West Siberian Basin, with tens of millions of barrels of oil equivalent per kilometer over large areas, define world class in marine source rocks since these basins are ranked number one and number two in the world by oil endowment. Until more data are available on other lacustrine basins, we offer the UEP of the studied Bohai Basin source rock as an example. In contrast, the UEP of the Bakken Formation source rocks (combined Upper and Lower Members) is relatively modest despite its world class unconventional oil endowment. The Bakken's effectiveness, despite its relatively low UEP, reflects the negligible migration saturation losses involved in charging the Middle reservoir Member. This illustrates that the commonly touted term world class can be rather meaningless. It needs to be considered in context given the task in hand: the greater the (vertical) migration losses incurred in charging reservoirs, the higher the UEP needed to create the charge needed to overcome them.

3-D reservoir characterization and hydrocarbon volumetric estimation of parts of Niger Delta Basin-Nigeria

Coupled interpretation and modeling of seismic and well log data, using geostatistical techniques was adopted to characterize reservoirs in a section of the Niger Delta Basin. The study was aimed at generating high resolution reservoir information such as spatial distribution of petrophysical properties, subsurface structures (e.g., faults and horizons) and estimation of hydrocarbon volume in a heterogeneous reservoir system. Five reservoirs with over twenty fault structures were delineated. The reservoir structural framework consists of antithetic and synthetic faults that influenced hydrocarbon flow dynamics within the field. Petrophysical properties were estimated and spatially distributed over the study area via variogram statistics. Both the sequential indicator and Gaussian simulations were performed to transform the pillar grids during the modeling process. Three realizations of the volumetrics were obtained for each of the reservoirs and the overall stock tank oil initially in place of the field, show low outcome of 245,720,570.40 stock tank barrels (STB) which indicates 90% probability of exceeding the quoted value, median outcome of 302,735,521.90 STB called the reality-oriented model (i.e., 50% probability) and a high outcome of 361,161,605.40 STB which has 10% probability of exceeding the estimated value. The gas zone estimate show low, median and high outcomes of 53,745.50, 56,487.60 and 60,618.50 million standard cubic feet (mmscf) respectively. Generally, results obtained show that an integration of well log and seismic data using geostatistical techniques can yield geological plausible reservoir models that can enhance production and management decisions in complex heterogeneous reservoir systems.

Prediction of oil flow rate through orifice flow meters: Optimized machine-learning techniques

Flow measurement is an essential requirement for monitoring and controlling oil movements through pipelines and facilities. However, delivering reliably accurate measurements through certain meters requires cumbersome calculations that can be simplified by using supervised machine learning techniques exploiting optimizers. In this study, a dataset of 6292 data records with seven input variables relating to oil flow through 40 pipelines plus processing facilities in southwestern Iran is evaluated with hybrid machine-learning-optimizer models to predict a wide range of oil flow rates (Qo) through orifice plate meters. Distance-weighted K-nearest-neighbor (DWKNN) and multi-layer perceptron (MLP) algorithms are coupled with artificial-bee colony (ABC) and firefly (FF) swarm-type optimizers. The two-stage ABC-DWKNN Plus MLP-FF model achieved the highest prediction accuracy (root mean square errors = 8.70 stock-tank barrels of oil per day) for oil flow rate through the orifice plates, thereby removing dependence on unreliable empirical formulas in such flow calculations.

Adaptive neuro-fuzzy algorithm applied to predict and control multi-phase flow rates through wellhead chokes

A Takagi-Sugeno adaptive neuro-fuzzy inference system (TSFIS) model is developed and applied to a dataset of wellhead flow-test data for the Resalat oil field located offshore southern Iran, the objective is to assist in the prediction and control of multi-phase flow rates of oil and gas through the wellhead chokes. For this purpose, 182 test data points (Appendix 1) related to the Resalat field are evaluated. In order to predict production flow rate (QL) expressed as stock-tank barrels per day (STB/D), this dataset includes four selected input variables: upstream pressure (Pwh); wellhead choke sizes (D64); gas to liquid ratio (GLR); and, base solids and water including some water-soluble oil emulsion (BS&W). The test data points evaluated include a wide range of oil flow rate conditions and values for the four input variables recorded. The TSFIS algorithm applied involves five data processing steps: a) pre-processing, b) fuzzification, c) rules base and adaptive neuro-fuzzy inference engine, d) defuzzification, and e) post-processing of the fuzzy model. The developed TSFIS model for the Resalat oil field database predicted oil flow rate to a high degree of accuracy (root mean square error = 247 STB/D, correlation coefficient = 0.9987), which improves substantially on the commonly used empirical algorithms used for such predictions. TSFIS can potentially be applied in wellhead choke fuzzy controllers to stabilize flow in specific wells based on real-time input data records.

Assessment of CO2‐enhanced oil recovery and associated geologic storage potential in the Michigan Northern Pinnacle Reef Trend

AbstractThis paper provides an improved estimate of CO2‐EOR (where CO2 is carbon dioxide and EOR is enhanced oil recovery) and CO2 storage potential for depleted oil fields in Michigan's northern pinnacle reef trend (NPRT). Our methodology is based on capturing data on reservoir performance from reefs currently undergoing CO2‐EOR operations in the NPRT (referred to as ‘monitored reefs’), and then applying them to other reefs within the NPRT (referred to as ‘catalog reefs’). For each monitored reef, we calculate fractional primary recovery, fractional incremental EOR recovery, net utilization ratio, and storage efficiency factor. The corresponding incremental oil recovery from EOR, storage capacity until end of EOR, and total CO2 injection needs are then estimated for each catalog reef and combined (over all monitored reefs) using a weighted averaging procedure. These weights are related to a statistical similarity measure that is calculated between each monitored reef and each catalog reef based on a number of variables related to production data, formation type, or descriptive geologic attributes. For the entire NPRT catalog of 383 reefs as used in this study, our results indicate 118 million (MM) stock tank barrels (STB) (1.88 × 107 Sm3) of incremental oil from EOR operations, corresponding to 49 MM metric tons (MT) of CO2 storage and 266 MM MT of total CO2 injection. However, approximately one‐third of the reefs provide two‐thirds of the potential for CO2‐EOR and geologic storage, assuming an economic threshold of 0.5 MM STB (80 000 Sm3) of incremental oil from EOR. © 2020 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons, Ltd.

Computer modeling and simulation for undersaturated primary drive recovery mechanism

The focus of this article is to test the capability of a three-dimensional undersaturated numerical reservoir simulator developed for prediction of actual field performance cases. The simulator development employs unconditional stable Crank–Nicolson second order in time approximation discretization scheme and preconditioned conjugate gradient iterative solver for the derived fluid flow equation. Furthermore, formation volume factor as a function of cell pressure is computed at each time step until bubble-point pressure is reached. The reservoir model is then coupled with a horizontal wellbore model in the simulator by placing a well optimally at the center of its drainage volume. The numerical simulation results show that the numerical solutions improve significantly with the addition of grid blocks. Graphical visualization surface and contour map plots show rapid and continuous average reservoir pressure depletion with time for an earliest possible determination and characterization of primary drive mechanisms. The rate of pressure depletion and recovery factor estimation (1.52%) are the two main characteristics used to identify depletion drive or rock and liquid expansion drive as the best-fit prospective drive for the reservoir model. The total cumulative production of 170,000 stock-tank barrels (MSTB) recovered in 1390 days is in agreement with the field data used. Sensitivity analyses with the numerical simulator illustrated the key impact of reservoir parameters on pressure depletion with less computational expensiveness. Finally, material balance incremental (0.995) and cumulative (1.005) error checks validate the simulator robustness within an acceptable tolerance limit.

Assessment of CO2 - EOR and Storage Capacity in South Sumatera and West Java Basins

A study of carbon dioxide-enhanced oil recovery (CO2-EOR) and storage capacity in South Sumatera and West Java Basins, Indonesia has been conducted in conjunctions with the project plans of Indonesia National Electric Company to build carbon capture and storage ready coal power plants in Bojonegara of West Java and Muara Enim of South Sumatera. The Bojonegara power plant comprises 2×1000 MWe Ultra Super Critical Units, while Muara Enim consists of 2×300 MWe subcritical units. Those two power plants will produce approximately 11 and 4 million tons of CO2 per year. The geology of South Sumatera and West Java Basins are proven to have kept oil and gas in place safely for long time periods and there are many oil and gas companies production still active in those basins. Those basins are confirmed to be used as storage of CO2, where capacity, injectivity, and confinement will be suitable to keep CO2 in place for a period of time. CO2 production from those power plants in South Sumatera and West Java may be offered to the nearby oil companies and transported to oil fields for CO2-EOR flooding to get additional revenue. A preliminary CO2-EOR screening has been done for the oil fields surrounding the power plants. There are two types of mechanisms for CO2-EOR, which depend on the nature of the oilfield: immiscible EOR and miscible EOR. Immiscible EOR occurs where the injected CO2 does not mix with the oil but instead displaces the oil from the area where the CO2 is injected and increases the pressure of the oil at the production wells so that it can be pumped out. Miscible EOR occurs where the supercritical CO2 mixes miscibility with the residual oil to make it less viscous and facilitating its flow to the production wells. A total of 127 oil fields in South Sumatera has been analyzed to select which of those fields fulfill CO2-EOR injection criteria. EOR reservoir screenings were performed on those oil fields on which detailed information was available using the screening criteria proposed by Taber et al. The criteria include a set of parameters such as API gravity, oil viscosity, current pressure, temperature, oil saturation, remaining oil, formation depth, thickness, porosity, permeability, and rock type which help to determine whether or not a reservoir is suitable for CO2-EOR injection. 96 fields are classified as miscible displacement while the remaining 31 fields are categorized as immiscible. The result shows that the potency of additional recovery from those fields is around 661 million stock tank barrels with CO2 requirement of approximately 243 million tonnes. In addition to EOR, pure CCS to inject the CO2 emission into depleted gas fields in West Java and South Sumatera regions is also considered. The maximum storage capacity of West Java gas fields is approximately 395 million tonnes, while the storage capacity of South Sumatera is around 537 million tonnes. The potential for storing CO2 in the saline aquifer was also calculated theoretically. The depleted gas fields and aquifers are considered enough to store the CO2 emission from the power plants as long as 25 years.

EOR Potential from CO2 Captured from Coal-Fired Power Plants in the Upper Cretaceous (Cenomanian) Woodbine Group, East Texas Basin, and Southeastern Texas Gulf Coast, USA

The East Texas Basin and southeastern Texas Gulf Coast contain a variety of co-located CO2 sources and sinks that may facilitate development of new clean-coal facilities. These facilities can be linked to mature oil fields with potential for enhanced oil recovery (EOR) from miscible CO2 floods. Twenty-three reservoirs in the East Texas Basin and southeastern Texas Gulf Coast, assuming a 15% recovery factor of original oil in place (OOIP), have a CO2-EOR potential for recovery of ~9,697,000 m3 [~62.2 million stock tank barrels] of oil. A network of new CO2 pipelines can link these fields to existing power plants near lignite mine mouths in east and southeast Texas. Representative oil fields in the Woodbine Group illustrate fluvial and deltaic facies variability and different sandstone-body architectures with varying controls on potential CO2 capacity. Reservoir heterogeneity, fluid flow, hydrocarbon production, and potential CO2 capacity in the Woodbine Group in the structurally simple East Texas field are mainly a function of facies architecture. The Woodbine Group in East Texas field contains a lower section of narrow and lenticular sandstone bodies in a fluvially dominated deltaic system. Pressure and production data indicate that additional oil recovery in the lower Woodbine deltaic section in East Texas field is low in muddy, low-permeability prodelta, and distal-delta-front facies. In contrast, oil recovery is greater in sandy distributary-channel sandstones. Core-plug data show that distributary-channel and channel-mouth-bar sandstones in the field have high median-permeability values, and therefore a greater potential for CO2 capacity. These deltaic deposits are overlain disconformably by an upper section of continuous, coarse-grained fluvial deposits that favor high CO2 capacity owing to Darcy-class permeability and extensive vertical and lateral reservoir continuity. In contrast, Woodbine fields in southeast Texas represent distal-deltaic facies. CO2 capacity and EOR potential in these fields are limited by thin distributary-channel and crevasse-splay deposits that contain abundant mudstone beds that may serve to segregate-injected CO2 into small reservoir compartments.

Geologic and Economic Criteria for Siting Clean-Coal Facilities in the Texas Gulf Coast, USA

The Texas Gulf Coast (TGC) contains the greatest number of favorably co-located CO2 sources and sinks in Texas that favor new potential clean-coal facilities. Areas in the TGC with clean-coal potential were delineated by mapping spatial linkages between coal- and lignite-bearing formations and geologic and infrastructure factors that include proximity to existing fields from mine-mouth power plants for enhanced oil recovery (EOR), length of new pipelines to transport CO2 from new clean-coal facilities to either EOR fields or to brine formations for deep storage, proximity to centers of electric load, and depth to subsurface coal for enhanced coalbed methane recovery. Other factors include thickness of brine formations for deep storage of CO2, groundwater and surface-water availability, and proximity to railroads for haulage of western U.S. coal feedstock. Geospatial analysis of maps portraying the distribution of these factors, together with data on volumes of oil recoverable from miscible CO2 flooding of oil fields, indicates that optimal areas for new clean-coal sites in the TGC are in east and southeast Texas. CO2 pipeline networks linking these sites to EOR fields are integral components of systems that can typically recover 5–50 million stock tank barrels from miscible CO2 flooding from each EOR field. Many of these fields with EOR potential (for example, Neches, Long Lake, Conroe, and Livingston) have a great potential for stacked CO2 storage, in which multiple reservoir zones can undergo EOR development and deeper zones in the field can accommodate excess CO2 from EOR operations.

Oil Release from Macondo Well MC252 Following the Deepwater Horizon Accident

Oil flow rates and cumulative discharge from the BP Macondo Prospect well in the Gulf of Mexico are calculated using a physically based model along with wellhead pressures measured at the blowout preventer (BOP) over the 86-day period following the Deepwater Horizon accident. Parameters appearing in the model are determined empirically from pressures measured during well shut-in and from pressures and flow rates measured the preceding day. This methodology rigorously accounts for ill-characterized evolution of the marine riser, installation and removal of collection caps, and any erosion at the wellhead. The calculated initial flow rate is 67,100 stock-tank barrels per day (stbd), which decays to 54,400 stbd just prior to installation of the capping stack and subsequent shut-in. The calculated cumulative discharge is 5.4 million stock-tank barrels, of which 4.6 million barrels entered the Gulf. Quantifiable uncertainties in these values are -9.3% and +7.5%, yielding a likely total discharge in the range from 4.9 to 5.8 million barrels. Minimum and maximum credible values of this discharge are 4.6 and 6.2 million barrels. Alternative calculations using the reservoir and sea-floor pressures indicate that any erosion within the BOP had little affect on cumulative discharge.

Polygenic formation model of the planet’s bituminous belts

In recent years, much attention has been paid to nontraditional hydrocarbon sources. Today the portion of nontraditional gas in the world extraction is 15% or 450 billion cubic meters, which hat makes up the volume of total gas exports from Russia. As is known, the easy-prospecting oil has been already found. The innovative technologies in geophysics, drilling, and excavation and the increased extraction coefficient expect further development and industrial compliance with these requirements. Based on calculations, the world oil reserves are now one trillion of stock tank barrels and one trillion barrels have been already extracted. The evergrowing demand for energy gives rise to the necessity of searching for and extracting more oil resources, and both these aspects are unique problems. The search for profitable petroleum deposits has become more and more difficult even in the leading companies. The increment of the world resources is a key vital question; therefore, the elaboration of criteria for the discovery of nontraditional deposits take on special significance in the economic respect. The authors are working out a conception that will be a guideline for future finding of the richest oil deposits in active geodynamic zones. For the first time, we suggest the polygenic formation model of the planet’s bituminous belts.

Northwest McGregor field CO2 Huff ‘n’ Puff: A case study of the application of field monitoring and modeling techniques for CO2 prediction and accounting

Northwest McGregor field CO2 Huff ‘n’ Puff: A case study of the application of field monitoring and modeling techniques for CO2 prediction and accounting

Using time-lapse seismic for field development at Nembe Creek, Nigeria

Nigeria is the largest oil producer in Africa and the 11th largest in the world. The majority of reserves are found along the country's coastal Niger River Delta. Nembe Creek Field, southwest of Port Harcourt (Figure 1), was discovered in 1973 and started production in 1977. This land/swamp field has a large STOIIP with an ultimate recovery of about 50%. Cumulative production as of January 2006 is about 643 million stock tank barrels (stb), thus leaving a huge opportunity that technologies such as time-lapse seismic and smart wells can impact, in addition to unlocking bypassed reserves.

MORE WELLS, MORE OIL—A CASE STUDY OF RESERVES GROWTH IN THE KENMORE FIELD

The Kenmore oil field in the Eromanga Basin of southwest Queensland was discovered in 1985. Since then, a further 32 wells have been drilled and more than 12.5 MMSTB of oil has been produced from the Birkhead Formation/Hutton Sandstone. Oil production over the last year has averaged 1,220 barrels per day totalling some 0.45 million stock tank barrels (MMSTB)Oil reserves in Kenmore were originally estimated at 2.2 MMSTB following the Kenmore–1 discovery well drilled in 1985. In the following 20 years, infill drilling, a 3D seismic survey, various reservoir studies and better -than-expected recovery efficiency, have steadily increased the ultimate recoverable reserves to the current estimate of 14.3 MMSTB.The growth of reserves at Kenmore is primarily attributed to better drainage of the complex reservoir framework within the lower Birkhead Formation resulting from recognition of the variable lateral connectivity of the reservoir. Due to the initial estimate of the ultimate field reserves being significantly smaller than now recognised and the resultant conservative drilling program, the economic value of the field was not maximised. This experience has implications for the ongoing development of the Kenmore field and suggests that other Birkhead/Hutton oil fields should be developed more aggressively to prevent history repeating itself.

Geological controls on remaining oil in Miocene fluvial and shoreface reservoirs in the Mioceno Norte area, Lake Maracaibo, Venezuela

Facies architecture and structure are the primary controls on reservoir geometry, fluid-flow pathways, and distribution of remaining oil in fluvial and shoreface reservoirs of Miocene age in the 46.7 km 2 Mioceno Norte area in northern Lake Maracaibo. This mature field is undergoing depletion and nearing the final stages of primary recovery. Although the area has produced oil since the 1940s, appreciable volumes of oil (commonly 400 to 1200X10 3 STB (stock tank barrels)/20-acre drainage area) remain in multiple, poorly contacted reservoir sandstones at the current 984 ft (300 m) well spacing. Detailed lithofacies maps document the control of sandstone architecture on hydrocarbon distribution and demonstrate that the current well spacing on a grid pattern is too large to recover efficiently the remaining oil. Moreover, the facies architecture influences water-cut patterns and the irregular advancement of inferred oil-water contacts on the western margin of the field. A wide variety of infill wells, recompletions, redrilled wells, horizontal wells, and water-injection wells is proposed. Approximately 80X10 6 STB of remaining oil will be produced by maintaining the current 984 ft (300 m) well spacing. However, an additional 46.5X10 6 STB can be produced with geologically targeted infill wells, recompletions and horizontal wells. In addition, new water-injection wells can appreciably increase oil recovery by enhancing sweep efficiency and providing pressure support.

Integration of Old and New Measurements To Optimize Redevelopment of the Lower Lagunillas Reservoir of Bloque IV, Lake Maracaibo, Venezuela

Summary The Lower Lagunillas of Bloque IV of the Bachaquero field is a supergiant reservoir that has been in production since 1956. We have carried out a pilot reservoir characterization study in the central part of the field, in which we have integrated all the available data into three-dimensional (3D) reservoir simulation models whose purpose is to optimize redevelopment of the area with horizontal wells. An analysis of the history of production was undertaken to gain an insight into the reservoir dynamics. This analysis indicated the inefficiency of gas injection in providing pressure support to the pilot study area and demonstrated the presence of active aquifer encroachment from the south. Anomalies in production behavior and fluid characteristics indicate both lateral and vertical compartmentalization of the reservoir. We have integrated Fourier transform infrared (FTIR) measurements of mineralogy from old cores with a comprehensive logging suite in a new well to re-evaluate older, sparse logging suites. The application of a mineral-based log evaluation and high-resolution processing of the new logs has led to a significant increase in estimates of oil initially in place in the study area. We have used a novel approach to estimate permeability in all wells in the study area. Combining these new evaluations with a revised geological model enabled us to recognize 11 geological layers throughout the area. Formation pressure measurements confirm that partial barriers to vertical communication exist between most of these layers. Cased hole saturation measurements and historical production data indicate an uneven sweep of these layers, such that five layers contain bypassed oil that could be recovered by horizontal wells. We have constructed very detailed simulation models that describe the lateral and vertical variation in petrophysical properties of each of these layers. These models have been used to select the optimum locations for horizontal wells and to optimize their drilling sequence and design. It is estimated that each of these wells could recover 1 to 1.5 million stock-tank barrels (STB) within 5 years. The first well drilled as a result of this study has produced dry oil at rates up to 469 BOPD from a zone not previously considered as a pay zone.