Commingled Wells Research Articles

Experimental simulation study on influencing factors of liquid production capacity in heterogeneous water drive reservoirs

Oilfield development involves a complex, dynamic flow process of oil and water, with reservoir characteristics and environmental conditions continually evolving as the field evolves. Particularly when a waterflooding reservoir reaches a stage of ultra-high water cut, prolonged waterflooding intensifies challenges in reservoir development: the exacerbation of reservoir heterogeneity and development behaviors disrupts the initial understanding of the reservoir's liquid production capacity from current development conditions. Thus, it becomes imperative to adjust the productivity prediction methods for oil wells in heterogeneous waterflooding reservoirs. Leveraging the flow simulation of reservoir micro channel networks, and integrating features such as the geometric characteristics of the reservoir percolation field, micro channel characteristics, interlayer differences of mixed layers, degree of plane heterogeneity, production pressure differentials, and fluid properties, a visual sand filling experimental model is established that adheres to specific similarity criteria. Using this sand filling experimental model, we simulate the percolation characteristics of oil–water two-phase flow during the waterflooding process, and uncover the diverse influencing factors and their varying degrees of impact on the oil-phase flow during this waterflooding phase. Qualitative and semi-quantitative percolation simulation experiments are employed to intuitively demonstrate the interlayer interference, degree of plane heterogeneity, and oil–water distribution in heterogeneous reservoirs, which influence the change in oil well productivity during waterflooding. This lays bare the microscopic percolation mechanisms behind the productivity changes in heterogeneous waterflooding reservoirs. The simulation experiment results show that the higher the permeability, the stronger the micro-heterogeneity, and the smaller the overall mobility increase after flooding, the smaller the JLDmax obtained by testing or calculation. At the same permeability, the greater the driving pressure difference, the greater the microscopic sweep coefficient within the pore network, and the greater the mobility increase after flooding, the greater the JLDmax. There is interlayer interference in commingled mining, and the higher the permeability of the high-permeability layer (the greater the interlayer difference), the higher the initial productivity of the commingled well. However, due to the high permeability layer being prone to flooding, resulting in ineffective water circulation, the low-permeability tube is difficult to completely flood, resulting in a small increase in overall mobility, and therefore, JLDmax is small. Water drive preferentially breaks through the high permeability zone on the plane, and the shape of the water drive sweep zone is controlled by the planar permeability gradient, the width of the high permeability zone, and the displacement pressure difference.

A PRODUCTION SPLITTING MODEL OF HETEROGENEOUS MULTI-LAYERED RESERVOIRS WITH COMMINGLED PRODUCTION

Production splitting is the basis for a proper understanding of the development effect of reservoirs when multiple layers are commingled to produce, and it is a difficult part of the development evaluation of this type of reservoir. Reservoirs with multiple layers are usually developed through commingled production. However, due to interlayer interference, the total output of commingled production is lower than the sum of individual production of each subordinate layer. It's significant to clarify the interlayer interference mechanism during layers with commingled production, establish an accurate splitting model of the production from subordinate layers, split the commingled production into each subordinate layer, and effectively understand the production level and remaining potential of the subordinate layers during commingled production. It is expected to develop a theoretical basis for the rational and effective development of multi-layered commingled production reservoirs. In this paper, a combination of multi-tube parallel displacement experiments and numerical simulations of a multi-layered reservoir with commingled production is used to analyze the influence of factors such as permeability ratio, production pressure difference, and crude oil viscosity on the interlayer interference mechanism. According to the research results, the interference coefficient is firstly introduced on the basis of the theoretical production formula of seepage flow. The change rate of the oil production splitting coefficient at the stage when the water cut is more than 80% is also proposed, and the production splitting model of subordinate layers in heterogeneous reservoirs is established, considering multiple factors. Taking multi-layered Reservoir A with commingled production as an example, this model is used to split the production of commingled wells. Results show that interlayer interference can be reduced by decreasing the permeability ratio and high permeability laminar fluidity, and increasing the production pressure difference. When the water content is greater than 80%, the oil production segmentation coefficient of the layers with high permeability decreases sharply with the increase of the water content. For the low-permeable layer, the situation is just the opposite. At the same time, based on the study of the interlayer interference mechanism coupled with the oil well radial flow production formula, the interference coefficient and the oil production segmentation coefficient change ratio are introduced. The findings of this study can help develop a more accurate model for production of subordinate layers in heterogeneous multi-layered reservoirs. The established splitting model is carried out using the data from two wells and four subordinate layers in Reservoir A, indicating that the accuracy of the proposed model is close to 90%.

Integrated Data Analysis Illuminates Commingled Smart Water-Injection Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206503, “Implementation and Intermediate Monitoring Outcomes of the First Commingled Updip Smart Water Injection Well in PA-B Platform Piltun-Astokhskoye Offshore Oil and Gas Field,” by Alexander V. Tsarenko, Valentin N. Tarsky, SPE, and Lisa Jane Robson, Sakhalin Energy Investment Company. The paper has not been peer reviewed. _ The objective of the complete paper is to share an evaluation of the background, drilling outcomes, and production and reservoir-pressure effects during 2 years of monitoring the first commingled updip smart water injector drilled in the Piltun area of the Piltun-Astokhskoye offshore oil and gas field in Sakhalin. The authors highlight details of the well-maturation decisions and expectations based on output of dynamic modeling studies. Setting The Piltun area consists of six main reservoir units (XXI-S, XXI-3, XXII-1, XXII-2, XXIII, and XXIV-2) being developed over two fault blocks (Block 1 and Block 2). All reservoirs have aquifers and gas caps, although the volumes, reservoir properties, and productivity of these reservoirs varies considerably, with the XXI-S and XXIV-2 reservoirs having the best rock properties and the highest recovery factors. Updip Water-Injection History In the original field development plan (FDP) created in 2008 and the reservoir management plan created in 2006, the Piltun area was to be developed by rows of commingled vertical downdip and updip water injectors (UDWIs), displacing oil to mid-rim vertical oil producers. However, the original UDWI concept was challenged early in development when the following geological surprises were encountered during drilling of the initial development wells: - The structure was significantly higher than expected at the crest of the field. - Thin, high-permeability (superfacies) layers were encountered in the producers and updip pilot holes. - The injectivity of the downdip injectors was much lower than expected and required an upgrade to the water-injection pumps. The FDP was reassessed in 2011. The design of the UDWIs was changed to long horizontal wells located at the gas/oil contact in the XXI-S, XXII-1, and XXIV-2 reservoirs only. The 2011 FDP assumed that early water breakthrough could be managed by smart-well technology in the oil producers. However, these producers experienced technical failures, and the plan to install smart completions in all mid-rim producers subsequently was aborted. In a 2015 FDP update, the design of the UDWIs was changed to vertical commingled wells equipped with a smart completion type, targeting only those reservoirs where clear incremental recovery and economic benefit was observed.

Geological and engineering controls on the differential productivity of CBM wells in the Linfen block, southeastern Ordos Basin, China: Insights from geochemical analysis

In view of the differential productivity of coalbed methane (CBM) wells in the Linfen block on the southeastern margin of the Ordos basin, geochemical analysis is performed to determine the hydrodynamic condition of coal reservoirs, identify the water and gas source of commingled wells, reveal different pressure drop mechanisms, and finally clarify the geological and engineering controls on the production performance. The positive correlations between average daily gas production and the concentrations of Na+, Cl‾, TDS, Sr, and Ba imply that strong hydraulic closure is the premise of high productivity. There is no obvious relationship between water and gas production. Commingled (5 + 8#) wells tend to produce more water than single-layered (5#) wells, because the No. 8 coal seam has more active hydrodynamic condition, which is proven by the lighter δ2H and δ18O and smaller Sr/Ba ratio of waters from commingled wells. The difficulty in pressure drop funnel expansion is the primary constrains for the single-layered wells, which is only resolved by the horizontal wells located in low structural positions at present characterized by increasing trends of TDS, Na+ and Cl‾ contents during drainage. The faster the ion concentration rises, the faster the pressure drop funnel expands and a high peak daily gas production can be quickly achieved. The L-shaped horizontal well is thought to be the most suitable well type due to its high gas yield, low time investment and engineering cost. Due to hydrodynamic heterogeneity, commingled wells often show strong interlayer interference and a change in the water-producing horizon from 5# to 8# coal, which is manifested in the tendency of Cl‾, Na+, and TDS to increase first and then decrease. By selecting superior lithologic assemblages and avoiding strong aquifers, relatively continuous and stable production of commingled wells can also be achieved. This study provides a basis for the further development of CBM in the Linfen block and enriches engineering geochemistry theory.

Pressure transient behavior and flow regimes characteristics of vertical commingled well with vertical combined boundary: A field case in XC gas field of northwest Sichuan Basin, China

The multilayered deposition is the main feature of the XC gas reservoir in the northwestern Sichuan Basin. The boundaries among layers of the XC gas reservoir is different. In this paper, we propose an extended pressure transient analysis model for vertical commingle well, considering different boundary radii and boundary types, to capture the Vertical Combined Boundary (VCB) effect on the pressure transient behavior and flow regime characteristics.The analytical solution is yielded by the Laplace transform, Bessel functions, Duhamel's superposition principle, and Stehfest inversion algorithm, and new flow regimes under different boundary combinations are identified by the pressure derivative curve. Taking the dual-layer VCB model as a type example, nine combinations of boundaries are analyzed. Compared with the current vertical commingled well model with the same boundary radii or single boundary types, this model has novel flow regimes controlled by the VCB.The research results indicate that the pressure derivative type curve during the novel flow regimes stage can diagnosis the VCB type. On the one hand, there are quantitative linear relationships between the pressure derivative feature value and interlayer heterogeneity of the VCB model with the same boundary radii. These linear relationships provide a new perspective to quickly capture interlay heterogeneity through the of the pressure derivative feature value. One the other hand, the pressure behavior and flow regimes of the VCB model with different boundary radii obey the successive superposition rule. This rule provides a method to recognize the VCB type with different boundary radii based on that of the VCB with the same boundary radii.Finally, a field case from the northwestern Sichuan Basin gas reservoir is discussed in detail to exhibit the workflow of our model application and validate the capability of our model.

Transient Behavior of Vertical Commingled Well in Vertical Non-Uniform Boundary Radii Reservoir

Transient behavior analysis, including rate transient analysis (RTA) and pressure transient analysis (PTA), is a powerful tool to investigate the production performance of the vertical commingled well from long-term production data and capture the formation parameters of the multilayer reservoir from transient well testing data. Current transient behavior analysis models hardly consider the effect of vertical non-uniform boundary radii (VNBR) on transient performances (rate decline and pressure response). The VNBR may cause an obvious novel radial flow regime and rate decline type, which can easily be mistaken as a radial composite reservoir. In this paper, we present a VNBR transient behavior analysis model, the extended vertical uniform boundary radii (VUBR), to investigate the rate decline behavior and pressure response characteristics through diagnostic type curves. Results indicate that the dimensionless production integral derivative curve or pressure derivative curve can magnify the differences so that we can diagnose the outer-convex shape and size of the VNBR. Therefore, it is significant to incorporate the effects of VNBR into the transient behavior analysis models of the vertical commingled well, and the model proposed in this paper enables us to better evaluate well performance, capture formation characteristics and diagnose flow regimes based on rate/pressure transient data.

A study of CO2 storage integrity with rate allocation in multi-layered aquifer

Most deep saline aquifers consist of multiple layers, and CO2 is generally injected through the injection well in a commingled form with one tubing string. Layer thicknesses and physical properties such as permeability and porosity vary from layer to layer because of differences in lithology and mineral compositions. When a heterogeneity such as a fault exists, if CO2 is rapidly introduced first into a certain layer, this CO2 reaches fault faster than other layers. Therefore, it is necessary to consider the characteristics of each layer in multi-layered aquifer, particularly in commingled well. In this study, rate allocation by layer was calculated in the multi-layered Pohang Basin aquifer, Korea, and whether CO2 reaches the fault and the pore pressure at the fault exceeds the fault reactivation pressure were investigated to evaluate the stability of the aquifer. In addition, the maximum CO2 storage capacity of the aquifer was estimated and we observed changes in trapping mechanisms over a 1,000-year period after the cessation of injection. The results of the analysis indicate that when up to 50 ktonnes of CO2 was injected into the Pohang Basin multi-layered aquifer over a two-year period, the rate allocations of the upper and lower layers were 70% and 30%, respectively. CO2 did not reach to the closest EF1 fault, and the pore pressure at this fault did not exceed the fault reopening pressure. The maximum possible storage capacity was conservatively calculated under the conditions of fault reactivation pressure (11.7 MPa) and maximum compressor capacity (14 MPa), indicating that a total of 160 ktonnes can be stably injected over six years without reaching the fault. In order to evaluate the stability of the aquifer, the changes in trapping mechanisms over a 1,000-year period were observed. According to the results, structural trapping decreased drastically, from 64.7% to 4.5%, over 1000 years. Meanwhile, solubility and residual trapping increased significantly, from 35.3% to 95.5%. Therefore, the data analyzed to date indicate that the project injecting CO2 in a commingled form from single tubing in the multi-layered Pohang Basin aquifer, Korea, has no possibility of CO2 leakage due to fault reopening.

Production Allocation on Commingled Two Layer Well Using Fingerprint Method

Production proportion ratio study of commingled well two layers reservoir has been developed by geochemistry approaching, with oil reservoir fingerpint methode by using Gas Chromatography then processed by Chemstation software. The study is developed to solve the commingled well production alocation problem in oil field. There are 4 oil samples will be analyzed to represent each layer and commingle production oil sample in 2009 and 2015.Result of study, figures out that oil fingerprint from commingle production has a difference as long as production time. Oil sample that taken from different commingle production time is predicted to produce a different ratio contribution form each layer of reservoir. Every layer reservoir has a different contribution from 2009 to 2015. Result of production proportion ratio study can be applied to decisionmaking of reservoir developement in an oil field, especially for well completion and enhanced oil recovery. This methode is proven to be a solution of commingle production problem of two layers reservoir. Fingerprint methode to determine production proportion ratio of commingled well production is the first in Indonesia.

Technology Update: Characterizing a Coal-Seam Gas Reservoir by Interpreting Permanent DTS Data

Technology Update In Australia’s Surat Basin, gas is contained in hundreds of coal seams, which have highly variable properties and are grouped into four distinct reservoir zones of similar qualities. Economically producing these wells from multiple reservoir units is generally favored and as a result, understanding the relative contribution to production by different zones at different times in the well’s life—and whether production is dominated by a single zone—adds value to planning future wells. The well designs are quite simple. An 8.5-in. wellbore is drilled from surface casing through the target coal seams. A 7-in. production casing and preperforated liner with an external casing packer and a cement stage tool is run to total depth. The external casing packer is deployed at the top of the reservoir, and the 7-in. casing is cemented in place through the stage tool above the packer. No external packers are installed between groups of coal seams (zones) to segregate production from each zone through the preperforated liner. Production tubing is installed in the well, which typically runs to the base of the preperforated liner, and a progressive cavity pump (PCP) is installed in the tubing to lift the water produced with the coal-seam gas (CSG) [dewater the well]. Gas production comes from the coal seams and flows around and through the preperforated liner, then up through the annular space, between the production liner/casing and the production tubing, to surface. The water flows to the bottom of the completion, where it is lifted up the production tubing by the PCP as shown in Fig. 1. Understanding Zonal Allocation Normally, production logging tools (PLTs) are run to obtain an understanding of zonal allocation in commingled wells. However, running PLTs in CSG wells can be expensive as it requires the PCP to be pulled out and the well to be lifted with gas. The switch to gas lift at shallow depth is not a normal operating condition and may affect the result. An additional issue is the unsegregated, openhole completion. With no external packers, neither the PLT tools nor the distributed-temperature sensor (DTS) fibers inside the liner can measure flow in the space between the liner and the sandface.

Real-Time Production Surveillance and Optimization in a Mature Subsea Asset

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181103, “Real-Time Production Surveillance and Optimization at a Mature Subsea Asset,” by Xiang Ma, Zachary Borden, Paul Porto, Damian Burch, Nancy Huang, Paul Benkendorfer, Lynne Bouquet, Peng Xu, Cassandra Swanberg, Lynne Hoefer, Daniel F. Barber, and Tom C. Ryan, ExxonMobil, prepared for the 2016 SPE Intelligent Energy Conference and Exhibition, Aberdeen, 6–8 September. The paper has not been peer reviewed. A real-time production-surveillance and -optimization system has been developed to integrate available surveillance data with the objective of driving routine production optimization. The system aims to streamline data capture, automate data quality assurance, integrate high- and low-frequency data to extract maximum value, optimize the design and analysis of commingled well tests, and provide real-time multiphase well-rate estimates for continuous well-performance evaluation. Introduction The technology was piloted in an offshore field consisting of stacked deepwater channel deposits developed with five individual subsea drill centers, 15 active oil producers, one gas injector, and five water injectors. Equipment is controlled remotely, and produced fluids are routed to surface by two 8-in. risers from each drill center. Produced gas is treated for use as fuel gas on the surface and for gas lift by reinjecting into each production well. All wells were originally deployed with a full suite of instrumentation, as well as valve-status sensors for each well flowline and riser. The three-phase separators on the surface use orifice plate meters for rate measurement. The approach taken was to integrate real-time data and physical models for real-time production surveillance and optimization. The deployed system uses software that incorporates in-house-developed techniques for continuous model tuning. First, a complete integrated production model (IPM) of the production system was built, spanning reservoir inflow and wells on the one hand and flowlines, risers, and topsides on the other. The IPM is embedded in a field management software platform that houses several standard work flows as well as proprietary algorithms. Calculation results and real-time data are visualized with a visualization application. As with other digital-oilfield applications, the key is continuous calibration of the physical models when field producing conditions change. The standard solution within the chosen field- management software relies on calibrating the well models with single-producing-well tests. However, most of the subsea wells in the asset have lost the ability to flow alone, and only commingled well tests are available. Operators thus resort to a test-by-difference protocol to obtain periodic well rates for allocation, which introduces significant errors when test conditions deviate largely from production conditions. To overcome this issue, a customized commingled well-test-analysis (CWTA) work flow was developed to analyze multisegment commingled well tests simultaneously.

A Production Estimation Algorithm in Commingled Oil Wells Based Kernel Partial Least Square

Commingling is employed in the petroleum industry to enhance oil recovery and reduce costs. It is of great importance to monitor the production of each oil well oilfields. Nowadays, more and more oilfields use chromatographic fingerprint to estimate single-zone production allocation. In order to insure the efficiency and affectivity of the commingled oil well exploiting, the productivity contribution of every single layer must be acquainted. Kernel partial least squares (KPLS) is a promising regression method for tackling nonlinear systems because it can efficiently compute regression coefficients in high-dimensional feature spaces by means of nonlinear kernel functions. Unlike other nonlinear partial least squares (PLS) techniques KPLS does not entail any nonlinear optimization procedures and has a complexity similar to that of linear PLS. Using the technology of crude oil chromatography fingerprint, an algorithm for predicting productivity contribution based on KPLS is proposed. The validity of the method is proved by laboratory artificial experiments. The maximum absolute error of predicted and real proportion is less than 10%. The model can also be applied to other wells which are similar to those used in the experiment. The experiment results show the prediction model is feasible.

The Application of Semi-quantitative Total Hydrocarbon Chromatography Technology in Determining Production Allocation of Individual Sand Layer in a Commingled Production Well

The authors present a case study of using semi-quantitative oil fingerprinting technology to correctly back allocate production of individual sand layer in commingled well. A large number of oil samples were collected over time and analyzed by gas chromatography (GC) for their oil fingerprints. The results showed that the production allocation of single layer in two-layer commingled well and the hydrocarbon concentrations of commingled oil were in a liner relationship. However, the production allocation of single layer and oil GC fingerprint parameters were in curvilinear relationship. The semi-quantitative oil fingerprinting technology was suitable for the case of two-layer commingled well, and three-layer commingled well with larger gas chromatography differences among oil of each layer.

Water flooding of the Oseberg Øst oil field, Norwegian North Sea: Application of formation water chemistry and isotopic composition for production monitoring

This case study demonstrates how natural heterogeneities of formation and injection waters can be applied to a number of production related applications, extending into the mature life of a reservoir. Break-through of injection water, identification and characterisation of production intervals and evaluation of responses to operational events are some of the possible applications during production. The Oseberg Øst oil field in the North Sea represents a complex situation with commingled production from all Brent Group formations. The Sr isotope composition is an excellent parameter for defining the natural baseline of formation water, with a good spatial resolution and vertical stratification. Aquifer water from the Utsira Formation is injected for pressure support, and reinjection of produced water has also been applied since the onset of water production. Utsira Formation water has high Mg, low Ba and low Sr content compared to the reservoir formation waters. Isotopic compositions (δ D and 87Sr/ 86Sr) are also distinct. A non-reactive behaviour of Ba and Sr is verified from binary cross-plots and geochemical modelling. Break-through of injection water could be identified in five production wells based on Ba/Mg ratios. In one of the reservoir compartments (Beta Saddle), water injection points were changed after approximately three years. The Ba/Mg ratio could also identify the second injection water break-through in one of the wells due to an intermediate period of higher formation water content. Since the Sr content in the Utsira water is low, the 87Sr/ 86Sr ratio is a good natural tracer for formation water movements even at high ratios of injected water. In particular, the vertical stratification of 87Sr/ 86Sr is useful for quantifying production from different intervals in commingled wells. A methodology for using operational events, such as production allocations or shut-ins, for characterisation of production zones is discussed.

Viability study of implementing smart/intelligent completion in commingled wells in an Australian offshore oil field

Simulating the automated action of smart well components represents a challenge in forecasting performance of such wells, and is fundamental to design decisions. Examples are wells equipped with inflow control valves (ICV), where zones have to be switched on, off or partially closed based on their performance relative to the rest of the wells/completions in the field, and where they share the same surface network and facilities constraints. This paper presents a study that has been carried out to justify installation of a surface controlled ICV in a group of wells in an offshore Australian field with commingled production. The merit of surface-controlled ICV versus uncontrolled commingled production has been compared. A numerical reservoir simulator program has been used to model reservoir performance and production from individual zones. Also, the wells and production network have been simulated using well flow simulator and a production network simulation software respectively. A simulation manager software is used to facilitate information exchange between the two simulation programs (production network and reservoir) and optimisation of the process. Proper control of ICVs is simulated based on reservoir and wellbore simulation data, which will result in maximum oil production of a field network system resulting in higher recovery. Also, we have done economic analysis for smart well completion implementation. The results of two aforementioned analyses (simulation study and economics) show that smart completion is viable for this field.

Calculation of the contribution of single-zone production by ultraviolet spectrum technique: A case study in well QHD32-6-3 field

Based on the established mathematic model and graphic interpretation, a new method, which is used to calculate the contribution of single-zone production in a commingled producing well by the ultraviolet spectrum technique, has been established. The standard plate was drawn using the extinction coefficient E of sample oils formulated artificially as y-axis and the wavelength as x-axis. The curve resulting from the UV analysis of sample oils in the commingled well was inserted into the standard plate and compared. The proportion of each single zone in the commingled producing well was identical with the proportion of the curve which is closest to the curve of sample oils formulated artificially. In the well QHD32-6-3 field, taking well A22 for example and using this method, the production contribution of a single zone was calculated. The result showed that the Nm4 zone is a major “contributor”, the proportion of the Nm4 zone is 70%, and that of the Nm1 zone is 30%. The ultraviolet spectrum technique provided a new reservoir geochemical technique of monitoring production contribution, especially for biodegraded heavy oil, but it has some limitation, just depending on the GC fingerprint technique.

The application of gas chromatography fingerprint technique to calculating oil production allocation of single layer in the commingled well

Gas chromatography fingerprint technique has the advantages of fast performance and low cost. It can be used to conduct analysis without interruption either in the field or at laboratory. This technique has been used successfully in such cases that conventional production logging techniques are powerless. Taking low-concentration anthracene as internal standard, we calculated the absolute concentrations of fingerprints, initially made some experiments directly on biodegradation of crude oils, and calculated production allocation in the Gudong Oil field. Compared with the production logging, this method has made up for the deficiencies of the former GC fingerprint technique. It will find wide applications in monitoring the trend of production in various oil-fields.

Characterizing the Greater Burgan Field: Use of Geochemistry and Oil Fingerprinting

Summary This study reports reservoir geochemistry findings on the Greater Burgan field by a multidisciplinary, multiorganizational team. The major objectives were to determine if unique oil fingerprints could be identified for the major producing reservoirs and if oil fingerprinting could be used to identify wells with mixed production because of wellbore mechanical problems. Three potential reservoir geochemistry applications in the Burgan field are: (1) evaluation of vertical and lateral hydrocarbon continuity, (2) identification of production problems caused by leaky tubing strings or leaks behind casing, and (3) allocation of production to individual zones in commingled wells. Results from this study show that while oils from the major reservoir units are different from each other, the differences are small. Furthermore, a number of wells were identified in which mixed oils were produced because of previous mechanical problems. Both transient pressure testing and distributed pressure measurements provided corroborative evidence of some of these findings. Other data show that Third Burgan oils are different in the Burgan and Magwa sectors, suggesting a lack of communication across the central graben fault complex. This finding supports the geologic model for the ongoing reservoir simulation studies. Success of the geochemistry project has spawned enlargement of the study in both size and scope.